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CA and EA Services
Huntington Field Comparative Assessment Report
Premier Oil UK Limited Assignment Number: A302470-S00 Document Number: A-302470-S00-REPT-005
Xodus Group
Xodus House, 50 Huntly Street
Aberdeen, UK, AB10 1RS
T +44 (0)1224 628300 E [email protected] www.xodusgroup.com
CA and EA Services – Huntington Field Comparative Assessment Report
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Huntington Field Comparative Assessment Report
A302470-S00 Client: Premier Oil UK Limited Document Type: Report Document Number: A-302470-S00-REPT-005
A01 03/01/2020 Issued for Use John
Foreman Nic Duncan Nic Duncan
R01 09/12/2019 Issued for Review John
Foreman Nic Duncan Nic Duncan
Rev Date Description Issued By Checked
By Approved
By Client
Approval
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CONTENTS
EXECUTIVE SUMMARY 5
1 INTRODUCTION 6
1.1 Background 6 1.2 Purpose 6 1.3 Report Structure 7 1.4 Terms, Abbreviations and Acronyms 7 1.5 References 8
2 COMPARATIVE ASSESSMENT METHODOLOGY 9
2.1 Overview 9 2.2 Scoping 10
2.2.1 CA Boundaries 10 2.2.2 Physical Attributes of Equipment 10 2.2.3 Decommissioning Groups 11 2.2.4 Decommissioning Options 11
2.3 Screening Phase 12 2.4 Preparation Phase 14 2.5 Evaluation Phase 14
3 HUNTINGTON AREA DECOMMISSIONING GROUPS 16
3.1 Decommissioning Groups for Full CA 16
4 CA - GROUP 1 - TRENCHED & BURIED RIGID PIPELINES 17
4.1 Group 1 Characteristics 17 4.2 Group 1 Decommissioning Options & Screening Outcome 17 4.3 Group 1 Decommissioning Options for Evaluation 19 4.4 Group 1 Evaluation Summary 20
5 CA - GROUP 3 - TRENCHED & BURIED FLEXIBLE PIPELINES & UMBILICALS 21
5.1 Group 3 Characteristics 21 5.2 Group 3 Decommissioning Options & Screening Outcome 21 5.3 Group 3 Decommissioning Options for Evaluation 23 5.4 Group 3 Evaluation Summary 24
6 RECOMMENDATIONS 25
6.1 Group 1 Recommendations 25 6.1.1 Safety 25 6.1.2 Environment 25 6.1.3 Technical 26 6.1.4 Societal 26
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6.1.5 Economic 26 6.1.6 Group 1 Evaluation Scope 26
6.2 Group 3 Recommendations 26 6.2.1 Safety 27 6.2.2 Environment 27 6.2.3 Technical 27 6.2.4 Societal 27 6.2.5 Economic 27 6.2.6 Group 3 Evaluation Scope 27
APPENDIX A EVALUATION METHODOLOGY 29
Appendix A.1 CA Evaluation Methodology 29 Appendix A.2 Differentiating Criteria & Approach to Assessment 29 Appendix A.3 Differentiator Weighting 34 Appendix A.4 Option Attributes 34 Appendix A.5 Option Pair-Wise Comparison 34 Appendix A.6 Visual Output and Sensitivities 36
APPENDIX B STAKEHOLDER CA WORKSHOP MINUTES 37
APPENDIX C GROUP 1 – DETAILED EVALUATION RESULTS 46
Appendix C.1 Group 1 Attributes Table 46 Appendix C.2 Group 1 Pairwise Comparison Matrices - Safety 50 Appendix C.3 Group 1 Pairwise Comparison Matrices - Environment 51 Appendix C.4 Group 1 Pairwise Comparison Matrices – Technical 52 Appendix C.5 Group 1 Pairwise Comparison Matrices – Societal 52 Appendix C.6 Group 1 Pairwise Comparison Matrices - Economic 52 Appendix C.7 Group 1 Results Charts 53
APPENDIX D GROUP 3 – DETAILED EVALUATION RESULTS 54
Appendix D.1 Group 3 Attributes Table 54 Appendix D.2 Group 3 Pairwise Comparison Matrices - Safety 58 Appendix D.3 Group 3 Pairwise Comparison Matrices - Environment 59 Appendix D.4 Group 3 Pairwise Comparison Matrices – Technical 60 Appendix D.5 Group 3 Pairwise Comparison Matrices - Societal 60 Appendix D.6 Group 3 Pairwise Comparison Matrices - Economic 60 Appendix D.7 Group 3 Results Charts 61
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EXECUTIVE SUMMARY
Premier Oil have conducted a Comparative Assessment (CA) for the decommissioning of the Huntington, Caledonia, Hunter, Rita and Johnston fields collectively. The following steps from the Oil and Gas UK CA Guidelines have been completed:
This CA report for the Huntington field presents the methodology, decisions taken, the preparation works carried out, and the outcomes (recommendations) from the internal and external (with stakeholders) workshops.
The CA for the Huntington field subsea infrastructure has focussed on two decommissioning groups - groups 1 and 3, as described in the table below.
All other decommissioning groups of the Huntington Subsea Infrastructure were confirmed at the CA Scoping and Screening stage to be fully removed from the field. The outcome of the CA process has made the following recommendations:
Grp Title Decommissioning Approach
1 Trenched & Buried Rigid Pipelines (CNS) Option 5 – Remove ends and remediate snag risk
Flowlines / umbilicals will be disconnected
Removal and recovery of surface laid sections out with existing trench
Rock placement to remediate snag risk from cut ends
3 Trenched & Buried Flexible Pipelines & Umbilicals (CNS)
Option 2b – Reverse reel without de-burial
Flowlines / umbilicals will be disconnected
No de-burial prior to removal
Recover by reverse reel
6 Spools & Jumpers Full Removal
7 Structures Full Removal
8 Protection / Stabilisation Full Removal
9 Moorings & Piles Full Removal
10 Dynamic Risers & Dynamic Umbilicals Full Removal
The decisions were reached on completion of an appropriate amount of preparatory study work, with clear decision outcomes. The buried sections of the trenched and buried rigid gas export pipeline will be the only Huntington subsea infrastructure remaining following decommissioning. All other infrastructure shall be fully removed.
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1 INTRODUCTION
1.1 Background
The Huntington Field in the Central North Sea consists of a subsea template with 6 wells, 3 production and 3 water injection. The template is tied back via a subsea manifold to an FPSO, the Voyageur Spirit. Processed oil is exported via shuttle tanker and dried gas is exported into the CATS system via an 11.8km 8” gas export pipeline (PL2805) and tee.
Figure 1.1 Huntington Field Schematic
1.2 Purpose
The purpose of this document is to present a Comparative Assessment (CA) for the Subsea Infrastructure of the Huntington Field in support of the Decommissioning Programme (DP). It is produced in satisfaction of the requirement to perform a CA for any potential derogation application for subsea equipment as detailed in the OGUK Decommissioning CA Guidelines ref. [1].
It describes the field infrastructure addressed, the decommissioning options considered, the CA methodology and the recommendations made during the CA process.
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1.3 Report Structure
This CA Report contains the following:
Section 1 – An introduction to the document and project, including acronyms and references.
Section 2 – An overview of the CA methodology and definition of the scoping and boundaries of the CA.
Section 3 – The decommissioning groups identified and the initial decommissioning approach.
Section 4 – The CA outcome obtained for Group 1 – Trenched & Buried Rigid Pipelines.
Section 5 – The CA outcome obtained for Group 3 – Trenched & Buried Flexible Pipelines & Umbilicals.
Appendix A – Evaluation Methodology.
Appendix B – Stakeholder CA Workshop Minutes.
Appendix C – Group 1 – Detailed Evaluation Results.
Appendix D – Group 3 – Detailed Evaluation Results.
1.4 Terms, Abbreviations and Acronyms
AHP Analytical Hierarchy Process
BAT Best Available Technology
BEIS Department of Business, Energy and Industrial Strategy
BEP Best Environmental Practice
CA Comparative Assessment
CNS Central North Sea
CoP Cessation of Production
CP Cathodic Protection
CSV Construction Support Vessel
DoB Depth of Burial
DSV Diver Support Vessel
EMT Environmental Management Team
FPSO Floating Production Storage and Offload
HAZID Hazard Identification
HSE Health and Safety Executive
JNCC Joint Nature Conservation Committee
MCDA Multi-Criteria Decision Analysis
MEI Major Environmental Incident
MFE Mass Flow Excavator
MS Much Stronger
MW Much Weaker
NFFO National Federation of Fishermen’s Organisations
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NORM Naturally Occurring Radioactive Material
OD Outside Diameter
ODU Offshore Decommissioning Unit
OGA Oil & Gas Authority
OGUK Oil & Gas UK
OIW Oil in Water
OPRED Offshore Petroleum Regulator for Environment & Decommissioning
PLL Potential for Loss of Life
POB Personnel on Board
S Stronger
SFF Scottish Fishermen’s Federation
SNS Southern North Sea
SRB Sulphate Reducing Bacteria
ToP Top of Pipe
ToU Top of Umbilical
VMS Very Much Stronger
VMW Very Much Weaker
W Weaker
1.5 References
1. OGUK Decommissioning CA Guidelines
OGUK – Guidelines for Comparative Assessment in Decommissioning Programmes, Dated: October 2015, ISBN: 1 903 004 55 1, Issue: 1.
2. BEIS Guidance Notes BEIS, Guidance Notes: Decommissioning of Offshore Oil and Gas Installations and Pipelines, Nov 2018.
3. CA Scoping Report Xodus, CA Scoping Report, AB-UK-XGL-LL-SU-RP-0001 B01, Apr 2019
4. CA Screening Report Xodus, CA Screening Report, AB-UK-XGL-LL-SU-RP-0002 B01, Sep 2019
5. Decommissioning Option Methodologies Report
Xodus, Decommissioning Option Methodologies, A-302470-S00-REPT-003, Sep 2019
6. Subsea HAZID Report Xodus, HAZID Report, A-302470-S00-REPT-004 A01, July 2019
7. Risk Analysis of Decommissioning Activities
Safetec, Joint Industry Project Report “Risk Analysis of Decommissioning Activities (http://www.hse.gov.uk/research/misc/safetec.pdf), 2005
8. Analytical Hierarchy Process T.L. Saaty, The Analytical Hierarchy Process, 1980
9. OGUK North Sea Pipeline Decommissioning Guidelines
Decommissioning of Pipelines in the North Sea Region – 2013, Issued by Oil & Gas UK
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2 COMPARATIVE ASSESSMENT METHODOLOGY
2.1 Overview
Comparative Assessment is a process by which decisions are made on the most appropriate approach to decommissioning. As such it is a core part of the overall decommissioning planning process being undertaken by Premier Oil for the Huntington Field Decommissioning Project (Subsea Infrastructure).
The OGUK Decommissioning CA Guidelines ref. [1] were prepared in 2015 by Oil and Gas UK, where seven steps to the CA process were recommended. Table 2.1 introduces each of these steps, along with a status and commentary to demonstrate the current position.
Title Scope Status Commentary
Scoping
Decide on appropriate CA method, confirm criteria, identify boundaries of CA (physical and phase).
✓ CA methodology and criteria established for screening to ensure appropriate evaluation phase.
CA Scoping Report [3]
Screening Consider alternative uses and deselect unfeasible options.
✓
Screening workshops were held in Q2 2019 the screening workshops were attended by members of the Premier Oil project team.
Screening outcomes are documented in CA Screening Report [4]
Preparation
Undertake technical, safety, environmental and other appropriate studies. Undertake stakeholder engagement.
✓ Studies identified during screening phase undertaken to inform the evaluation of the remaining options. Detailed in Section 2.4.
Evaluation Evaluate the options using the chosen evaluation methodology.
✓
Internal workshops held Q4 2019 and Stakeholder Workshop on 8th October 2019
Evaluation methodology described in Section 2.5 and outcomes detailed in Section 4 and 5. More detail can be found in Appendix A and in the Decommissioning Option Methodologies Report [5]
Recommendation
Document the recommendation in the form of narrative supported by charts explaining key trade-offs.
✓
The emerging recommendations for the decommissioning options selected are as identified during the Stakeholder Workshop and as detailed in the CA Report (this document). Recommendations can be found in Section 6.
Review Review the recommendation with internal and/or external stakeholders.
✓ The Stakeholder CA Review Workshop was held on 8th October 2019 and the minutes can be found in Appendix B.
Submit
Submit to OPRED as part of/alongside Decommissioning Programme.
✓ Planned Q1 2020
Table 2.1: CA Process Overview and Status
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2.2 Scoping
The scoping phase of the CA process addresses the following elements:
Boundaries for the CA;
Physical attributes of equipment;
Decommissioning options.
These are addressed in the following sub-sections.
2.2.1 CA Boundaries
The applicable boundaries for the CA are as follows:
The following will be complete prior to the Huntington subsea infrastructure decommissioning scope commencing:
All template wells will have been fully plugged and abandoned;
All risers will be disconnected from the FPSO and riser bases;
Risers shall have been recovered;
The FPSO will have departed the field.
Huntington Field subsea infrastructure is as follows:
All structures including their foundations;
All rigid and flexible subsea flowlines;
All flexible risers and dynamic umbilical;
Gas Export Pipeline;
All control and chemical jumpers;
All spools;
All umbilicals / cables;
All mattresses and deposits;
All drill cuttings;
The FPSO moorings and anchor chains.
2.2.2 Physical Attributes of Equipment
All equipment within the scope of the Huntington Field Decommissioning Project (subsea infrastructure) is listed along with the physical attributes that define the equipment. Attributes considered include the following:
Structures:
Type;
Weight / size / shape;
General arrangement;
Installation method / foundation type;
Integrity issues.
Pipelines / Flowlines / Spools:
Pipeline number;
Type (rigid / flexible);
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Service (gas / oil / water);
Material / diameter / wall thickness / coatings / length;
Seabed configuration (trenched / buried / surface laid);
Details of crossings / mattresses;
As-left cleanliness / ability to clean lines;
Integrity issues.
Umbilicals / Cables / Jumpers:
Material / diameter / wall thickness / coatings / length;
Seabed configuration (trenched / buried / surface laid);
Details of crossings / mattresses;
As-left cleanliness / ability to clean lines / chemicals used;
Integrity issues.
All equipment associated with Huntington Field Decommissioning Project (subsea infrastructure) along with their physical attributes are listed in full in the CA Scoping Report ref. [3] with a summary of the equipment included in Table 3.1 herein.
2.2.3 Decommissioning Groups
Once the equipment to be decommissioned and their attributes are captured, it is desirable to group similar equipment together. This has the benefit that many items can be considered as a single group and can reduce the number of items for consideration from potentially hundreds, down to a few, thus streamlining the process. For the Huntington Decommissioning Project (Subsea Infrastructure) the decommissioning groups, along with a list of each individual item that makes up the population of those groups, is detailed in full within the CA Scoping Report ref. [3]. A brief summary of the decommissioning groups identified is included in Table 3.1 herein.
2.2.4 Decommissioning Options
With the decommissioning groups established, all potential decommissioning options for each of the groups are identified. The base case for all groups is full removal as per the BEIS Guidance Notes ref. [2] and it is only those decommissioning groups where default full removal is not considered to be the clear recommended solution, that alternative decommissioning options are considered.
Alongside full removal options, the following partial removal scenarios should be considered as specified in the BEIS Guidance Notes ref. [2] and OGUK North Sea Pipeline Decommissioning Guidelines ref. [9].
Re-Use.
Full Removal:
Cut and Lift - Cut pipe into small sections and recover;
Reverse Installation without de-burial – Recover pipe using reverse s-lay or reverse reeling;
Reverse Installation with de-burial – Recover pipe using reverse s-lay or reverse reeling.
Leave In-Situ with Major Intervention:
Rock cover entire length including surface laid sections out with trench / cover;
Re-Trench and bury entire length including surface laid sections out with trench / cover.
Leave In-Situ with Minor Intervention:
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Rock cover areas of spans, exposure and shallow burial. Remove surface laid sections out with trench / cover;
Trench and bury areas of spans, exposure and shallow burial. Remove surface laid sections out with trench / cover;
Cut and Lift areas of spans, exposure and shallow burial. Remove surface laid sections out with trench / cover;
Accelerated Decomposition of lines using reverse cathodic protection / chemicals / etc.
Leave In-Situ and Minimal Intervention:
Cut and Lift surface laid sections out with trench / cover only.
Leave In-Situ and Do Nothing.
Table 3.1 lists the decommissioning groups and identifies those which were judged to be appropriate for decommissioning by full removal and those where full removal was not considered the clear recommended solution. Of those groups where full removal was not considered the clear recommended solution, the proposed decommissioning options for each of those groups are detailed as follows:
Section 4.2 for Group 1 – Trenched and Buried Rigid Pipelines;
Section 5.2 for Group 3 – Trenched and Buried Flexible Pipelines & Umbilicals.
2.3 Screening Phase
The screening phase of the comparative assessment was carried out during a series of workshops held in Q2 2019. The methodology adopted, workshop attendance and outcomes obtained are detailed fully in the CA Screening Report ref. [4]. The methodology is briefly summarised below.
Identify decommissioning groups for full removal;
Review proposed decommissioning options for each remaining group;
Assess decommissioning options and record assessment and outcome in screening worksheets;
Record actions required to support retained decommissioning options;
Compile Screening Report.
The decommissioning options for the remaining groups were assessed against the primary assessment criteria suggested in the OGUK Decommissioning CA Guidelines ref. [1]. These are:
Safety;
Environmental;
Technical;
Societal;
Economic.
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The assessment was performed using a coarse Red / Amber / Green method, as recommended in the OGUK Decommissioning CA Guidelines ref. [1]. An additional category of ‘showstopper’, coloured dark grey, was used. These categories are described Table 2.2.
Category Description
Attractive The option is considered attractive i.e. it has positive attributes in terms of the criterion being assessed.
Acceptable The option is considered acceptable i.e. its attributes are not positive or negative in terms of the criterion being assessed.
Unattractive The option is considered unattractive i.e. it has negative attributes in terms of the criterion being assessed.
Showstopper The option is considered unacceptable. Should an option be assessed as unacceptable against any of the criteria, no further assessment is required.
Table 2.2: Screening Assessment Categories
The cumulative assessment for each decommissioning option was then captured based on some basic ground rules. These are:
Three or more criteria assessed as red resulted in the option being screened out (red).
For similar full removal options, the likely least onerous option was retained (green) with any more onerous option considered as a sub-set of the less onerous option (light grey).
For similar leave in-situ options, the most onerous option was retained (green) with any less onerous options considered as a sub-set of the more onerous option (light grey).
This approach was considered appropriate to ensure that the worst-case full removal options were compared to the less onerous leave in-situ options. This ensures, during the evaluation phase, that the assessment is not skewed such that leave in-situ options are selected over full removal options.
The outcomes for each group are summarised in Table 4.2 and Table 5.2.
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2.4 Preparation Phase
During the preparation phase, detailed studies / analyses are conducted to provide information to support the Evaluation phase of the Comparative Assessment. The detailed studies / analyses that may be required are often identified early in the CA process. These studies / analyses are then supplemented by additional studies / analyses identified during the screening phase of the CA.
The studies / analyses conducted during the preparation phase of the CA process are as follows:
Integrity Assessment A high-level assessment of the residual integrity of the Group 3 flowlines in order to screen the reverse reel options for this group in or out.
Accelerated Decomposition Review A review of the latest status within industry of options for performing accelerated decomposition of rigid flowlines.
Method Statements Detailed method statements were developed for options carried forward to ascertain the activities and resources required to deliver the option.
Emissions Assessment Fuel consumption and atmospheric emissions assessment performed for options carried forward based upon activities and resources identified in method statements.
Environmental Impact Review Environmental impact reviews were conducted for options carried forward in areas of planned discharges, unplanned discharges and seabed disturbance based on activities and resources identified in method statements. Underwater noise impact was based on a qualitative assessment of the vessels and activities employed as detailed in the method statements.
Each of the above studies is detailed in the Decommissioning Option Methodologies Report ref. [5].
The findings of the studies / analyses are gathered in preparation for the evaluation phase of the CA. The key information obtained from these studies / analyses, used during the evaluation phase are provided in the attributes tables, included in Appendix C and Appendix D.
2.5 Evaluation Phase
The evaluation phase of the comparative assessment is where the remaining decommissioning options for each group are evaluated against each other. This evaluation process is conducted according to the OGUK Decommissioning CA Guidelines ref. [1] and employs the data obtained during the preparation phase as summarised in the attributes tables, included in Appendix C and Appendix D.
The evaluation phase was performed during several evaluation workshops where the decommissioning project team and field partners were represented. This enabled the supporting information for each of the decommissioning groups and associated decommissioning options to be interrogated and increased in maturity and definition.
Once the evaluation of the remaining decommissioning groups and options was ready, a CA Workshop was convened with external stakeholders; the CA process to date was described and the evaluation of the remaining options was reviewed. This CA Stakeholder Workshop enabled the invited stakeholders to gain familiarity with the evaluation methodology and the information the generated through the supporting studies and analyses. It also allowed the evaluation to be challenged in key areas and, at the culmination of the workshop, outcomes for each of the decommissioning groups were validated.
The CA Stakeholder Workshop was held at Premier Oil’s offices in Kingswells, Aberdeen on Tuesday October 8th, 2019. The attendees were as detailed in Table 2.3.
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Name Company Role
Robert Willison
BEIS OPRED ODU
Decommissioning Manager
Drew Bond Assistant Decommissioning Manager
Debbie Taylor Senior Decommissioning Manager
Nicola Abrams BEIS OPRED EMT Environment Manager
Doug Stewart JNCC
Offshore Industries Advisors Manager
Thomas Fey Offshore Industries Advisors
Ian Rowe NFFO Offshore Liaison
Steven Alexander SFF
Offshore Liaison
Andrew Third Industry Advisor
Hywel Williams HSE Pipelines Specialist HM Inspector
Pieter voor de Poorte
Premier Oil
Subsea Decommissioning Lead
Paul Newby Subsea Engineer (Decommissioning)
Lilla Onodi Decommissioning Engineer
Margaret Christie Environmental Advisor
Martyn Akers Technical Safety Lead
Kate Arman Asset Manager
Phil McIntyre Asset Manager
David Hunt Neptune Energy Decommissioning Manager
Nic Duncan
Xodus
Project Manager
John Foreman Comparative Assessment Lead
Jenny Smith Environmental Consultant
Table 2.3: Stakeholder Workshop Attendees & Roles
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3 HUNTINGTON AREA DECOMMISSIONING GROUPS
Table 3.1 lists all decommissioning groups identified for the Huntington Area Subsea Infrastructure. Early CA scoping and screening activities, detailed in full in the CA Scoping Report ref. [3] and the CA Screening Report ref. [4], identified the decommissioning groups where full removal is the recommended decommissioning approach (highlighted in grey).
The remaining groups are subjected to the remainder of the CA process to identify the recommended decommissioning option. These outcomes are also captured in Table 3.1. Note that the group numbers align with those in Table 2.2 of the CA Screening Report ref. [4].
Grp Title Description Decommissioning
Approach
1 Trenched & Buried Rigid Pipelines (CNS)
All trenched and buried, rigid pipelines, located in the Central North Sea (CNS).
Subject to full Comparative Assessment
3 Trenched & Buried Flexible Pipelines & Umbilicals (CNS)
All trenched and buried, flexible flowlines and umbilicals located in CNS.
Inclusion of flexible flowlines and umbilicals in the same group is deemed appropriate as they share similar design and manufacture characteristics, consisting of multiple layers of metals and polymers
Subject to full Comparative Assessment
6 Spools & Jumpers All rigid tie-in spools and elector-hydraulic and chemical jumpers across all fields
Full Removal
7 Structures All subsea structures across all fields Full Removal
8 Protection / Stabilisation All protection, support and stabilisation materials such as mattresses and grout bags across all fields.
Full Removal
9 Moorings & Piles Group 9 contains the mooring lines and suction anchors associated with the Huntington Field FPSO (Voyageur Spirit).
Full Removal
10 Dynamic Risers & Dynamic Umbilicals
Group 10 contains all flexible risers and dynamic umbilicals across all fields.
Full Removal
Table 3.1: Decommissioning Groups and Initial Decommissioning Recommendation
Note that groups 2, 4 and 5 are not included in this table as they are applicable to Southern North Sea (SNS) fields only, Huntington is Central North Sea (CNS) and therefore does not have any equipment belonging to these groups.
3.1 Decommissioning Groups for Full CA
In summary, the decommissioning groups for the Huntington Area subsea Infrastructure where full removal was not considered to be the clear recommended solution and that are to be subjected to the full CA process are:
Group 1 – Trenched & Buried Rigid Pipelines (CNS)
Group 3 – Trenched & Buried Flexible Pipelines & Umbilicals (CNS)
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4 CA - GROUP 1 - TRENCHED & BURIED RIGID PIPELINES
4.1 Group 1 Characteristics
The items that make up Group 1 for the Huntington Field and their key characteristics are listed in Table 4.1. This information was taken from the CA Scoping Report ref. [3].
ID Description OD
(inches) Length
(km) Weight
(T)
PL2805 11.8km 8” gas export pipeline, trenched and buried 8” 11.8 1,288
Table 4.1: Group 1 Items
4.2 Group 1 Decommissioning Options & Screening Outcome
During the Screening Phase, all potential decommissioning options were assessed against the Safety, Environmental, Technical, Societal and Economic criteria using a coarse, red / amber / green methodology. The assessment performed and the outcomes are detailed fully in the CA Screening Report ref. [4] and summarised in Table 4.2.
Group 1 – Trenched & Buried Rigid Pipelines
Category Option Description Discussion
Re-use 1 – Re-use - Leave pipeline in-situ for use in any potential new
developments
Ruled out as a showstopper as there were no potential re-use in-situ options for the
Huntington Gas Export line.
Full removal
2a – Cut and lift with de-burial
- Pipeline will be disconnected
- De-burial of pipeline using MFE
- Recover by cutting into sections and removal
Retained as the least onerous and credible Full Removal option.
2b – Reverse reel without de-burial
- Pipeline will be disconnected
- No de-burial prior to removal
- Recover by reverse reel
Ruled out on the basis that the line does not have the required integrity for reverse reeling
without de-burial.
2c – Reverse reel with de-burial
- Pipeline will be disconnected
- De-burial of pipeline using MFE
- Recover by reverse reel
Ruled out on the basis that the line does not have the required integrity for reverse reeling with de-burial.
2d – Lift and cut without de-burial
- Pipeline will be disconnected
- No de-burial prior to removal
- Recover to vessel with cut on vessel
Ruled out on the basis that the line does not have the required integrity for recovery to vessel for cutting.
2e – Lift and cut with de-burial
- Pipeline will be disconnected
- De-burial of pipeline using MFE
- Recover to vessel with cut on vessel.
Ruled out on the basis that the line does not have the required integrity for recovery to vessel for cutting.
Leave in-situ
(major intervention)
3a – Rock placement over entire line
- Pipeline will be disconnected
- Rock placement over full length of pipeline to address areas of spans, exposure & shallow burial (potentially less than 0.4m ToP)
- No recovery of pipeline.
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. There is no benefit in fully rock covering lines already fully buried.
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Group 1 – Trenched & Buried Rigid Pipelines
Category Option Description Discussion
Leave in-situ
(major
intervention)
3b – Retrench and bury entire line
- Pipeline will be disconnected
- Re-trench and backfill full length of pipeline to remove areas of spans, exposure & shallow burial depth (potentially less than 0.4m Top of Pipe (ToP))
- No recovery of pipeline
- No introduction of new material
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. There is no benefit in trenching lines already fully buried.
Leave in-situ
(minor intervention)
4a – Rock placement over exposures
- Pipeline will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cuts ends
- Rock placement at all areas of spans, exposure and shallow burial depth (potentially less than 0.4m ToP)
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. As there are no areas to address, this option becomes the same as Option 5.
4B – Trench & bury
exposures
- Pipeline will be disconnected
- Removal and recovery of surface laid sections out
with existing trench
- Rock placement to remediate snag risk from cut ends
- Trench / bury areas of spans, exposure and shallow burial depth (potentially less than 0.4m ToP)
- Minimal introduction of new material
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. As there are no areas to address, this option becomes the same as Option 5.
4C – Remove exposures
- Pipeline will be disconnected
- Removal and recovery of surface laid sections out
with existing trench
- Rock placement to remediate snag risk from cut ends
- Removal of areas of spans, exposure and shallow burial depth (potentially less than 0.4m ToP) using cut and lift techniques, including de-burial where required)
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. As there are no areas to address, this option becomes the same as Option 5.
4D – Accelerated decomposition
- Pipeline will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
- Introduce material / techniques to accelerate the
decomposition process
- Potential options include reverse polarity CP,
Sulphate Reducing Bacteria (SRBs), chemicals, etc.
Ruled out due to the novelty associated with delivering accelerated decomposition solutions. Whilst research is being conducted, no solutions are near market / commercially viable at this time.
Leave in-situ
(minimal intervention)
5 – Remove ends and remediate snag risk
- Pipeline will be disconnected
- Removal and recovery of surface laid sections out
with existing trench
- Rock placement to remediate snag risk from cut ends
Retained as a viable leave in-situ option as there are no areas of spans, exposure or shallow burial. Removing the ends of the line out with the trench presents a leave in-situ option that should be evaluated.
Leave in-situ (do nothing)
6 – Leave as-is
- There will be no planned subsea intervention
- Appropriate legislative considerations shall be addressed and any advisory zones implemented for
remaining subsea infrastructure
Ruled out as a safety showstopper due to the sections of line out with the trench leaving an unacceptable potential
snagging risk.
Table 4.2: Group 1 Decommissioning Options & Screening Summary
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4.3 Group 1 Decommissioning Options for Evaluation
The decommissioning options for Group 1 that remained after screening and which were taken forward to the evaluation phase are therefore:
Full Removal
2a – Cut and lift with de-burial
Leave in-situ (minimal intervention)
5 – Remove ends & remediate snag risk
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4.4 Group 1 Evaluation Summary
Group 1 – Trenched & Buried Rigid Pipelines
Note: for full attributes tables and assessment see Appendix C
Evalu
ati
on
Safe
ty
Option 5 is assessed as the most preferred option.
Option 5 is preferred to Option 2a from a risk exposure to Operations Personnel perspective. This is due to the longer durations associated with the offshore scope to cut the line into sections and recover in Option 2a versus removing the line ends only in Option 5. This also returns more material to shore for handling which also increases the risk exposure.
With respect to Other Users, Option 2a has a much higher number of vessel days and a higher number of vessel transits to and from site. While the increased safety impact on Other Users is expected to be small, it is sufficient to express a small preference for Option 5.
Option 5 is preferred from a High-Consequence Events perspective as it has much lower potential for dropped objects than 2a due to the high number of lifts associated with Option 2a.
Option 2a is preferred to Option 5 in the Legacy Risk criterion due to the line being fully removed. The difference in risk profile between Option 2a and Option 5 is assessed as minimal as the remaining line is fully trenched and buried in Option 5. Overall, Option 5 is preferred over Option 2a as it is lower risk in all safety categories other than residual risk.
En
vir
on
men
t
Option 5 is assessed as the most preferred option.
Option 5 is preferred to Option 2a from an Operational Marine Impact perspective as 2a requires extended vessel operations, diamond wire cutting and MFE operations which slightly increases the noise impact and potential for planned and unplanned discharges. All impacts are relatively minor, but the cumulative impact results in a small preference for Option 5.
Both options are considered equally preferred from an Atmospheric Emissions perspective as the fuel use and atmospheric emissions are largely similar. They are also equally preferred from an Other Consumptions perspective as, while the impact from processing all returned material in the full removal option is lower, this was insufficient to express a preference.
Option 5 is preferred with respect to Seabed Disturbance as Option 2a disturbs a much greater area of seabed during de-burial of lines by MFE with the seabed taking a long time to recover in this geographic location.
Option 2a is preferred from a Legacy Marine Impacts perspective as there is no legacy marine impact as line is removed. There is also a small area of permanent habitat change caused by rock cover in Option 5.
Note: the environmental impact of all decommissioning options is low and the differences between the options are minor.
Te
ch
nic
al
Option 5 is assessed as the most preferred option.
Both options use largely proven technology and routine operations. The extensive cut & lift and de-burial operations in Option 2a do, however, carry more risk of a technical failure. As such Option 5 is preferred.
So
cie
tal
Option 2a is assessed as the most preferred option.
With respect to Societal impact on Fishing, there is no preference between the two options. While Option 2a may appear to be preferable as it involves full removal of the line, it also causes disruption to fishing operations from the de-burial and removal of the line, which may impact nephrops fishing activities prevalent in this area.
Option 2a is preferred from a Societal impact on Other Users perspective as there is a significantly higher quantity of useful material being returned than in Option 5.
Eco
no
mic
Option 5 is assessed as the most preferred option.
From a short-term cost perspective, Option 2a is around 12 times more expensive than Option 5. For long-term costs, there are none associated with Option 2a as it is full removal but for Option 5 there are legacy costs associated with monitoring, surveying and managing potential snag hazards. The total short-term plus long-term costs are still significantly less for Option 5, as such this is the preferred option.
Su
mm
ary
Overall, Option 5 is assessed as the preferred option.
Option 5 was clearly preferred against the Safety, Environment and Technical criteria whereas Option 2a was only preferred marginally from a Societal perspective.
Once the Economics criterion was considered, this strengthens the preference for Option 5.
Option 5 – Remove ends and remediate snags will form the emerging recommendation for the decommissioning option for Group 1.
Table 4.3: Group 1 Evaluation Summary
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5 CA - GROUP 3 - TRENCHED & BURIED FLEXIBLE PIPELINES & UMBILICALS
5.1 Group 3 Characteristics
The items that make up Group 3 and their key characteristics are listed in Table 5.1. This information was taken from the CA Scoping Report ref. [3].
ID Description OD
(inches) Length
(km) Weight
(T)
PL2806 10” production flexible flowline, trenched and buried
10” 1.86 343
PL2807 4” gas lift flexible flowline, trenched and buried
4” 1.87 91
PL2808 8” water injection flexible flowline, trenched and buried
8” 1.83 188
PLU2809 Static 6” static umbilical, trenched and buried 6” 1.8 93
Table 5.1: Group 3 Items
5.2 Group 3 Decommissioning Options & Screening Outcome
During the Screening Phase, all potential decommissioning options were assessed against the Safety, Environmental, Technical, Societal and Economic criteria using a coarse, red / amber / green methodology. The assessment performed and the outcomes are detailed fully in the CA Screening Report ref. [4] and summarised in Table 5.2.
Group 3 – Trenched & Buried Flexible Pipelines & Umbilicals
Category Option Description Discussion
Re-use 1 – Re-use - Leave flowlines / umbilicals in-situ for use in any
potential new developments
Ruled out as a showstopper as there were no potential re-use in-situ options for these short, in field lines.
Full removal
2a – Cut and lift with de-burial
- Flowlines / umbilicals will be disconnected
- De-burial of flowlines / umbilicals using MFE
- Recover by cutting into sections and removal
Ruled out as a more onerous full removal option than Option 2b.
2b – Reverse reel without
de-burial
- Flowlines / umbilicals will be disconnected
- No de-burial prior to removal
- Recover by reverse reel
- Lines vary up to 10" diameter
Retained as the least onerous and credible Full Removal
option.
2c – Reverse reel with de-burial
- Flowlines / umbilicals will be disconnected
- De-burial of flowlines / umbilicals using MFE
- Recover by reverse reel
- Lines vary up to 10" diameter
Ruled out as a more onerous full removal option than Option 2b.
2d – Lift and cut without de-burial
- Flowlines / umbilicals will be disconnected
- No de-burial prior to removal
- Recover to vessel with cut on vessel
Ruled out as a more onerous full removal option than Option 2b.
2e – Lift and cut with de-burial
- Flowlines / umbilicals will be disconnected
- De-burial of flowlines / umbilicals using MFE
- Recover to vessel with cut on vessel.
Ruled out as a more onerous full removal option than Option 2b.
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Group 3 – Trenched & Buried Flexible Pipelines & Umbilicals
Category Option Description Discussion
Leave in-situ
(major intervention))
3a – Rock placement over entire line
- Flowlines / umbilicals will be disconnected
- Rock placement over full length of flowline / umbilical to address areas of spans, exposure & shallow burial (potentially less than 0.4m ToP / ToU)
- No recovery of flowlines / umbilicals
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. There is no benefit in fully rock covering lines already fully buried.
3b – Retrench and bury entire line
- Flowlines / umbilicals will be disconnected
- Re-trench and backfill full length of flowline / umbilical to remove areas of spans, exposure & shallow burial depth (potentially less than 0.4m Top of Pipe (ToP) /
Top of Umbilical (ToU))
- No recovery of flowlines / umbilicals
- No introduction of new material
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. There is no benefit in trenching lines already fully buried.
Leave in-situ
(minor
intervention)
4a – Rock placement over
exposures
- Flowlines / umbilicals will be disconnected
- Removal and recovery of surface laid sections out
with existing trench
- Rock placement to remediate snag risk from cuts
ends
- Rock placement at all areas of spans, exposure and shallow burial depth (potentially less than 0.4m ToP /
ToU)
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. As there are no areas to address, this option becomes the same as Option 5.
4B – Trench & bury exposures
- Flowlines / umbilicals will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
- Trench / bury areas of spans, exposure and shallow burial depth (potentially less than 0.4m ToP / ToU)
- Minimal introduction of new material
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. As there are no areas to address, this option becomes the same as Option 5.
4C – Remove exposures
- Flowlines / umbilicals will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
- Removal of areas of spans, exposure and shallow burial depth (potentially less than 0.4m ToP / ToU) using cut and lift techniques, including de-burial where required)
Ruled out as a technical showstopper as there are no areas of spans, exposure or shallow burial. As there are no areas to address, this option becomes the same as Option
5.
4D – Accelerated decomposition
- Flowlines / umbilicals will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
- Introduce material / techniques to accelerate the
decomposition process
- Potential options include reverse polarity CP, Sulphate Reducing Bacteria (SRBs), chemicals, etc.
Ruled out as a technical showstopper as accelerated decomposition not a viable solution for flexible flowlines / umbilicals due to their construction.
Leave in-situ
(minimal
intervention)
5 – Remove ends and remediate
snag risk
- Flowlines / umbilicals will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
Retained as a viable leave in-situ option as there are no areas of spans, exposure or shallow burial. Removing the ends of the line out with the trench presents a leave in-situ option that should be evaluated.
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Group 3 – Trenched & Buried Flexible Pipelines & Umbilicals
Category Option Description Discussion
Leave in-situ (do nothing)
6 – Leave as-is
- There will be no planned subsea intervention
- Appropriate legislative considerations shall be addressed and any advisory zones implemented for remaining subsea infrastructure
Ruled out as a safety showstopper due to the sections of line out with the trench leaving an unacceptable potential snagging risk.
Table 5.2: Group 3 Decommissioning Options and Screening Summary
5.3 Group 3 Decommissioning Options for Evaluation
The decommissioning options for Group 3 that remained after screening and which were taken forward to the evaluation phase are therefore:
Full Removal
2b – Reverse reel without de-burial
Leave in-situ (minimal intervention)
5 – Remove ends & remediate snag risk
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5.4 Group 3 Evaluation Summary
Group 3 – Trenched & Buried Flexible Pipelines and Umbilicals
Note: for full attributes tables and assessment see Appendix D
Safe
ty
Option 2b is assessed as the most preferred option.
Option 2b is preferred to Option 5 from a risk exposure to Operations Personnel perspective. This is due to the longer durations associated with the offshore scope to cut the line end sections into short sections and their recovery in Option 5 versus efficient reverse reeling of the lines in Option 2b. The increased risk exposure from the increased quantity of material returned to shore for handling was insufficient to offset the increased offshore risk exposure.
With respect to Safety risk to Other Users, Option 2b and Option 5 are both equally preferred due to a largely similar numbers of vessel days and transits. They are also equally preferred from a High-Consequence Events perspective as the potential for dropped objects is similar due to the similar number of lifts. The HAZID indicated that the potential for High Consequence Events from an integrity failure of the line during reverse reeling would be negligible due to no personnel being exposed on the high-tension side of the tensioner.
Option 2b is preferred to Option 5 in the Legacy Risk criterion due to it being a full removal option. The difference in risk profile between Option 2b and Option 5 is assessed as minimal as the remaining line is fully trenched and buried in Option 5. Option 2b is therefore preferred over Option 5 as it is preferred in two Safety categories with the others being equal.
En
vir
on
men
t
Option 2b and Option 5 are assessed as equally preferred.
Option 2b and Option 5 are equally preferred from an Operational Marine Impact perspective as the noise impacts and potential for unplanned discharges is similar for both options. Although there would be higher operational discharges from reverse reeling the lines (2b), as all contents would be released in a single discharge, the impact of this is expected to be low due to the small inventory remaining after these lines have already been cleaned and flushed and therefore insufficient to express a preference.
Both options are considered equally preferred from an Atmospheric Emissions perspective as, while there is more fuel use and atmospheric emissions for Option 5, this differential was considered insufficient to express a preference. They are also equally preferred from an Other Consumptions perspective as, while the impact from processing all returned material in the full removal option is lower, this was insufficient to express a preference.
Option 5 is preferred with respect to Seabed Disturbance as Option 2b disturbs a greater area of seabed during reverse reeling the lines through cover.
Option 2b is preferred from a Legacy Marine Impacts perspective as there is no legacy marine impact as the lines are removed. There is also a small area of permanent habitat change caused by rock cover in Option 5.
Note: the environmental impact of all decommissioning options is low and the differences between the options are minor.
Te
ch
nic
al
Option 5 is assessed as the most preferred option.
Both options use largely proven technology and routine operations. However, there is potential for the reverse reeling option to fail, requiring the decommissioning solution to be revisited. As such Option 5 is preferred.
So
cie
tal
Option 2b and Option 5 are assessed as equally preferred.
With respect to Societal impact on Fishing, there is no preference between the two options. Whilst Option 2b may appear to be preferable as it involves full removal of the lines, it also causes disruption to fishing operations during the reverse reeling of the lines, which may impact nephrops fishing activities prevalent in this area.
Option 2b and Option 5 are equally preferred from a Societal impact on Other Users perspective as while there is more useful material returned in Option 2b, there is also more material destined for landfill which cancels this out.
Eco
no
mic
Option 2b is assessed as the most preferred option.
From a short-term cost perspective, Option 2b is around half the cost of Option 5. For long-term costs, there are none associated with Option 2b as it is full removal but for Option 5 there are legacy costs associated with, surveying and managing potential snag hazards. The total short-term plus long-term costs are significantly lower for Option 2b, as such this is the preferred option.
Su
mm
ary
Overall, option 2b is assessed as the preferred option.
Option 2b was preferred against the Safety criterion and equally preferred against the Environmental and Societal criteria.
Option 5 was preferred from a Technical perspective.
Without including economics, there is a small preference for Option 5. Once the Economics criterion is included, this preference changes to a small preference for Option 2b.
As including economics results in a preference for a full removal option, Option 2b – Reverse reeling without de-burial will form the emerging recommendation for the decommissioning option for Group 3.
Table 5.3: Group 3 Evaluation Summary
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6 RECOMMENDATIONS
The outcomes obtained from performing the comparative assessment of the decommissioning groups and decommissioning options for the Huntington area subsea infrastructure are summarised here.
There were several groups where full removal was the recommended decommissioning approach without any further comparative assessment. These are:
Group 6 – Spools & Jumpers
Group 7 - Structures
Group 8 – Protection / Stabilisation
Group 9 – Moorings & Piles
Group 10 – Dynamic Risers & Dynamic Umbilicals
The full comparative assessment process was applied to the remaining decommissioning groups (1 and 3). The recommended decommissioning options for these groups follow below.
6.1 Group 1 Recommendations
The recommended decommissioning option for Group 1 – Trenched & Buried Rigid Pipelines (CNS) is:
Option 5 – Remove ends and remediate snag risk
Flowlines / umbilicals will be disconnected
Removal and recovery of transition and surface laid sections out with existing trench
Rock placement to remediate snag risk from cut ends
The following sections provide a summary of the evaluation of the two most viable Group 1 decommissioning options (Option 2a and Option 5) against the five criteria and why this recommendation has been made.
6.1.1 Safety
Option 2a has twice the risk exposure of Option 5 due to the extended durations required for cutting the entire line into section and recovering them rather than just the line ends out with the trench. In addition, Option 2a poses a slightly higher risk to Other Users from the larger number of vessel days and vessel transits and has higher potential for High Consequence Events from dropped objects as there are a much higher number of lifts through the splash zone. Option 2a is considered preferable to Option 5 from a Legacy Risk perspective as the line is fully removed. This preference is small however, as the line left in-situ in Option 5 is fully trenched and buried and is therefore expected to present a negligible potential for snagging.
Overall, there is a preference for Option 5 from a Safety perspective.
6.1.2 Environment
Option 2a has higher Operational Marine Impact due to more vessel noise, more subsea cutting noise and greater potential for unplanned discharges from the extended vessel and cutting operations associated with cutting the full pipeline vs. just the end sections. There will also be more seabed disturbance with Option 2a from the MFE de-burial of the line required to cut it into small sections.
Both options perform similarly from an Emissions and Consumptions perspective and Option 2a is preferred from a Legacy Marine Impact as the line is fully removed.
Overall, there is a preference for Option 5 from an Environmental perspective.
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6.1.3 Technical
While both options use largely routine activities and methods, Option 2a carries a higher risk of technical failure due to the longer duration cut and lift operations associated with the full pipeline removal rather than just the end section removal in Option 5. As such, Option 5 is preferred from a Technical perspective.
6.1.4 Societal
Both Options 2a and 5 have a similar impact on fishing as, although the lines will be fully removed in Option 2a, there will be disturbance caused to fishing activities from the de-burial and cutting operations. This is particularly disruptive to the nephrop fishing activities prevalent in this area. Option 5 will cause less disruption, but the pipeline will be left in-situ, albeit fully trenched and buried.
Option 2a is preferred to Option 5 with respect to the amount of useful material being returned from the cut and lift operations. Overall there is a slight preference for Option 2a from a Societal perspective.
6.1.5 Economic
The short-term costs associated with executing Option 2a where the line is fully removed are much higher (around 12 times higher) than for the much smaller scope associated with executing Option 5. Option 5 does however, have long-term costs associated with monitoring and surveying required to manage potential snag risks in the future, but these are calculated to be <£1m and therefore relatively insignificant in economic terms. The total costs (short-term + long-term) are significantly less for Option 5 and therefore this is preferred from an Economic perspective.
6.1.6 Group 1 Evaluation Scope
It should be noted that the evaluation session conducted for Group 1 – Trenched & Buried Rigid Pipelines (CNS) included lines for both the Huntington field (as described in Section 4.1) and Caledonia lines. This approach was deemed appropriate for the evaluation workshops as these fields are being decommissioned by Premier Oil in a similar time frame. It also reduced the burden on stakeholder attendance by combining elements in similar geographic areas, environmental conditions and characteristics.
As the reporting of the recommendation for Group 1 is by field (this Huntington CA Report) but the evaluation was conducted collectively (Huntington & Caledonia), the outcome for Group 1 was tested for validity by the project team by reducing the scope to just Huntington lines / Caledonia lines and confirming that the judgements made between the options remained valid.
Given that the decommissioning programme may be conducted as a collective campaign, this approach is considered appropriate and acceptable.
6.2 Group 3 Recommendations
The recommended decommissioning option for Group 3 - Trenched & Buried Flexible Pipelines & Umbilicals (CNS) is:
Option 2b – Reverse reel without de-burial
Flowlines / umbilicals will be disconnected
No de-burial prior to removal
Recover by reverse reel
Lines are between 4” and 10” diameter
The following sections provide a summary of the evaluation of the two most viable Group 3 decommissioning options (Option 2b and Option 5) against the five criteria and why this recommendation has been made.
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6.2.1 Safety
Option 2b has a third of the exposure risk that Option 5 has due to the efficiency of reverse reeling the short lines versus the extended duration required for cutting and removing line ends from 4 lines. Both options are similar with respect to vessel days and transits and therefore the safety risk to Other Users is considered equal. The options are also considered to have similar risk for high consequence events as there is a similar number of lifting operations. Option 2b is preferred from a Legacy Risk perspective due to the lines being fully removed. This preference is small however, as the lines left in-situ in Option 5 are fully trenched and buried and are therefore expected to present a small potential for snagging.
Overall, there is a preference for Option 2b from a Safety perspective.
6.2.2 Environment
Both options have similar Environmental performance. Option 2b has a higher Operational Marine Impact due to discharge of the line contents from reverse reeling. The impact of this discharge is expected to be low as the lines will be flushed and cleaned prior to removal. Option 5 has Higher Operational Marine Impact from the longer durations with vessels on site. These minor differentiators cancel each other out and as such, both options are equally preferred from an Operational Marine Impact perspective. There is higher fuel use and atmospheric emissions associated with Option 5, but the difference is not significant enough to warrant a preference. This is also the case with Other Consumptions. Option 5 is preferred from a seabed disturbance as there is less impact than the reverse reeling operations where the lines are pulled through existing cover. Option 2b is preferred from a Legacy Marine Impact perspective as the lines are fully removed.
Overall, both options are equally preferred from an Environmental perspective.
6.2.3 Technical
Both options do employ largely routine operations although Option 2b carries a higher risk of technical failure due to uncertainty around the integrity of the lines for reverse reeling operations. As such, Option 5 is preferred from a Technical perspective.
6.2.4 Societal
Both Options 2b and Option 5 have a similar impact on fishing as, although the lines will be fully removed in Option 2b, there will be disturbance caused to fishing activities from the reverse reeling operations. This is particularly disruptive to the nephrop fishing activities prevalent in this area. Option 5 will cause less disruption, but the lines will be left in-situ, albeit fully trenched and buried.
Option 2b returns more useful material for recycling than Option 5, but also returns more material that is likely to end up in landfill which is a negative societal impact. As such, the options are largely similar from a societal perspective.
6.2.5 Economic
The short-term costs associated with executing Option 2b where the line is fully removed by reverse reeling is around half that for the partial removal in Option 5. This reflects the efficient nature of reverse reeling operations and the short line lengths. There are no legacy costs associated with the full removal option versus around £1 million associated with surveying and monitoring required for the partial removal in Option 5. As such, Option 2b is preferred from an Economic perspective.
6.2.6 Group 3 Evaluation Scope
It should be noted that the evaluation session conducted for Group 3 – Trenched & Buried Flexible Pipelines & Umbilicals (CNS) included lines for both the Huntington field (as described in Section 5.1) and Caledonia lines. This approach was deemed appropriate for the evaluation workshops as these fields are being decommissioned by Premier Oil in a similar time frame. It also reduced the burden on stakeholder attendance by combining elements in similar geographic areas, environmental conditions and characteristics.
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As the reporting of the recommendation for Group 3 is by field (this Huntington CA Report) but the evaluation was conducted collectively (Huntington & Caledonia), the outcome for Group 3 was tested for validity by the project team by reducing the scope to just Huntington lines / Caledonia lines and confirming that the judgements made between the options remained valid.
Given that the decommissioning programme may be conducted as a collective campaign, this approach is considered appropriate and acceptable.
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APPENDIX A EVALUATION METHODOLOGY
Appendix A.1 CA Evaluation Methodology
Premier Oil has selected a Multi Criteria Decision Analysis (MCDA) methodology for the evaluation phase of the CA. This methodology uses a pairwise comparison system based on the methodologies of the Analytical Hierarchy Process (AHP) by T.L. Saaty, described in various publications, such as Analytical Hierarchy Process ref. [8]. This allows the relative importance of each differentiating criteria to be judged against each other in a qualitative way, supported by quantification where appropriate. The key steps for the evaluation phase of the CA are as follows:
Define Differentiating Criteria – this was completed in Q2 2019 and listed in Appendix A.2
Define Options – completed as part of CA Screening;
Pre-populate worksheets for internal CA workshops – based on all the studies undertaken the worksheets were pre-populated in advance of the internal CA workshops;
Perform internal CA workshop;
Discuss attributes of each option against each differentiating criteria – the discussion was recorded ‘live’ during the workshop in order that informed opinion and experience was factored into the decision-making process;
Perform scoring (see Section Appendix A.5);
Perform sensitivity analyses to test the decision outcomes;
Export worksheets as a formal record of the workshop attendees’ combined opinion on the current preferred options, the ‘Emerging Recommendations’;
Evaluate whether the CA needs to ‘recycle’ to the Preparation phase to obtain any further information to help inform decision making;
Discuss Emerging Recommendations with stakeholders (October 2019); and
Recycle process as required prior to decision on the selected options which will be presented in the Decommissioning Programme and assessed in the Environmental Impact Assessment.
The sections below describe how the MCDA methodology has been applied.
Appendix A.2 Differentiating Criteria & Approach to Assessment
A key step in setting up the CA was agreeing and defining the appropriate criteria that differentiates between each of the tabled options. As a starting point, the criteria considered for this CA were taken from the BEIS Guidelines for Decommissioning of Offshore Oil and Gas Installations and Pipelines which are as follows:
Safety
Environmental
Economic
Technical
Societal
These differentiating criteria were found to be appropriate for the decommissioning options tabled and were taken forward as the primary differentiating criteria for the CA. Additional sub-criteria and definitions were added for clarity and are shown in
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Criteria Sub-Criteria Description Approach to Assessment
1. Safety
1.1 Operations Personnel
This sub-criterion considers elements that impact risk to operations personnel and includes, project team, project vessel crew, diving teams, supply boat crew, and survey vessel crew. It should be noted that crew changes are performed via port calls. Any requirement for handling HazMat / NORM shall also be addressed here. Potential for Loss of Life (PLL) metrics were
calculated for each option. This allows a quantified direct comparison between options.
1.2 Other Users
This sub-criterion covers the impact associated with the risk to other users. Considers elements such as collision impact whilst performing activities. Users such as fishing vessels, commercial transport vessels and military vessels are considered.
1.3 High Consequence Events
This sub-criterion relates to any inherent potential for high consequence events i.e. major accident hazard. It applies to all onshore and offshore personnel involved in the project. Considerations such as dropped object concerns, support vessel risks, are considered.
A coarse HAZID was conducted to identify elements associated with the options that had potential for High Consequence Events. The coarse HAZID also addressed the legacy risk component associated with the options.
1.4 Legacy Risk
This sub-criterion addresses residual safety risk to other sea users i.e. fishermen, military vessel crews, commercial vessel crews and passengers, other sea users, that is provided by the option. Issues such as residual snag risk, collision risk, etc. may be considered.
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Criteria Sub-Criteria Description Approach to Assessment
2. Environmental
2.1 Operational Marine Impact
This sub-criterion addresses the marine environmental impact caused by performing the decommissioning option. Covers both planned impacts (inherent to the option being assessed) and potential unplanned impacts (accidental releases, both large and small in scale and encompassing Major Environmental Incidents (MEIs)). Impacts may be from Project Vessels, Supply Boats, Survey vessels, etc.
Examples include; Noise generated by vessels, cutting operations, any explosives, etc., discharges from vessels and from removing infrastructure such as residual pipeline contents.
Planned and unplanned marine impacts are narrative judgement informed by estimates of volumes / composition of any releases.
Impacts from vessels are qualitative in nature.
Marine noise impact is a qualitative judgement informed by the vessel durations, subsea cutting operations and other operations that generate marine noise.
2.2 Atmospheric Emissions & Fuel Consumption
This sub-criterion addresses the atmospheric emissions, fuel consumption and energy consumption from performing the decommissioning option. This may be from Project Vessels, Survey vessels, etc.
Impacts may be greenhouse gas emissions such as CO2, NOx, SO2, etc. Fuel and energy consumption is included and is tightly correlated to atmospheric emissions.
Not considered:
Energy / emissions / resource consumption required to replace materials not recovered for re-use or recycling which is covered in 2.3 Other Consumptions.
Fuel use, emissions and energy consumption are calculated from vessel operations using IP2000 ref. [X] factors for vessel fuel use and emissions. Fuel use, and emissions provided in metric tonnes. Energy provided in joules.
2.3 Other Consumptions
This sub-criterion addresses the environmental impact caused by the amount of resource consumption associated with the option. It covers elements such as environmental impact from processing returned materials, the use of quarried rock or other new material and any production of replacement materials for equipment left in-situ.
Consumptions such as rock / steel / other fabrications are quoted in metric tonnes.
Impact of recycling / processing returned material and replacing leave-in-situ material is quoted in metric tonnes of CO2. The CO2 figures allow a direct, quantitative comparison between options.
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Criteria Sub-Criteria Description Approach to Assessment
2. Environmental
2.4 Seabed Disturbance
This sub-criterion addresses the direct and indirect seabed disturbance caused by performing the decommissioning option. Impacts that are both permanent and temporary in nature are considered. The level of impact caused and any specific seabed concerns, such as protected areas or habitat changes may be covered.
Assessment based on quantifying the area of disturbance and by type of disturbance (dredging, rock dump, trenching, backfilling, mass flow excavation) in combination with an understanding of the baseline environment in the area as shown by the outputs from the environmental surveys.
2.5 Legacy Marine Impacts
This sub-criterion addresses the marine environmental impact caused after the decommissioning option has been performed. Covers the long-term impact of any infrastructure left in-situ such as release of materials into the marine environment, environmental impact from legacy monitoring and remediation i.e. planned and unplanned releases from vessels, vessel noise, etc.
Planned and unplanned marine impacts are narrative judgement informed by estimates of volumes / composition of any releases and the duration these may occur over.
Impacts from vessels are qualitative in nature.
Marine noise impact is a qualitative judgement informed by the vessel durations, subsea cutting operations and other operations that generate marine noise.
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Criteria Sub-Criteria Description Approach to Assessment
3. Technical 3.1 Technical Risk
This sub-criterion relates to the various technical risks that could result in a major project failure i.e. failure to deliver the decommissioning option broadly within the timescale / budget / endorsed decommissioning programme. Consideration is given to: Technical Novelty / Track Record, where the novelty of the technical solution is considered. Technical Challenges / Consequence of Failure to deliver the such as amendment to decommissioning approach and Potential for Showstoppers can be captured along with impact on the schedule due to overruns from technical issues such as operations being interrupted by the weather. Technical Feasibility and Technical Maturity is also considered.
Scored 1 – 3 with 1 being least technically feasible and 3 most technically feasible.
4. Societal
4.1 Fishing
This sub-criterion addresses the impact of the option on commercial fishing operations. It includes consideration of impacts from both the decommissioning activities any residual impacts post decommissioning such as reinstatement of access to area.
Scored 1 – 3 with 1 being a proportionally large area lost for fishing and 3 being a minimal area
4.2 Other Users
This sub-criterion addresses any positive or negative socio-economic impacts on other users, where the impact may be from dismantling, transporting, treating, recycling and land filling activities relating to the decommissioning option.
Additionally, Issues such as impact on the health, well-being, standard of living, structure or coherence of communities or amenities are considered here e.g. business or jobs creation, increase in noise, dust or odour pollution during the decommissioning option which has a negative impact on communities, increased traffic disruption due to extra-large transport loads, etc.
Scored 1 -3 with 1 being significant long-term impact to communities and 3 being minimal.
5. Economic
5.1 Short-term Costs
This sub-criterion addresses the cost of delivering the option as described. No long-term cost element is considered here.
Cost data (£ k)
5.2 Long-term Costs
This sub-criterion addresses the costs associated with any long-term liabilities such as on-going monitoring and any potential future remediation costs.
Cost data (£ k)
Table 6.1: Sub-criteria Definition
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Appendix A.3 Differentiator Weighting
The 5 differentiating criteria all carry a 20% weighting. That is, all criteria are neutral to each other. Figure 6.1 shows the pairwise comparison matrix. Premier Oil decided that equal weightings offer the most transparency and a balanced view from all perspectives.
Criteria
1. S
afe
ty
2. E
nvir
on
men
tal
3. T
ech
nic
al
4. S
ocie
tal
5. E
co
no
mic
Weig
hti
ng
1. Safety N N N N N 20%
2. Environmental N N N N N 20%
3. Technical N N N N N 20%
4. Societal N N N N N 20%
5. Economic N N N N N 20%
Figure 6.1: Example Pairwise Comparison Matrix (N = Neutral)
Appendix A.4 Option Attributes
The next step in the CA process was to describe and discuss the attributes of each option with respect to each of the differentiating criteria. In preparation, all relevant data and information developed during the preparation phase were pre-populated into the attributes table for each option. Appendix C and Appendix D contain the completed Attributes Tables for Groups 1 and 3 respectively.
Any additional discussion around the relative merits of the options was also recorded in the attributes matrix. A summary discussion of why options are considered more or less attractive with respect to each of the differentiating criteria was also recorded. An easy-to-read version of this matrix was supplied to stakeholders as part of the recommendation review process.
Appendix A.5 Option Pair-Wise Comparison
Once the option attributes were compiled and discussed, a pair-wise comparison was performed for each of the differentiating criteria where the proposed options were compared against each other. The pairwise comparison adopted in this case used phrases such as stronger, much stronger, weaker, much weaker, etc. to make qualitative judgements (often based on quantitative data) of the options against each other. Adopting these phrases rather than the more common numerical ‘importance scale’ from the Analytical Hierarchy Process (AHP) is often more intuitive and representative of the sentiment of a workshop.
One of the challenges of applying the numerical importance scale historically, is that often when scoring a pair of options against each other as a score of 3, delegates implied the comparison was 3 times better, etc. rather than ‘slightly better’ as the importance scale suggests.
To manage this, Premier Oil chose to apply the principles of the AHP by replacing numbers in the pairwise comparison matrix with a narrative or descriptive approach. This is already programmed into the AHP in the
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importance scale explanations (see Table 6.2). It was agreed that three positions from equal (and their reciprocals) would be sufficient for this CA. These positions were:
Title Scope Relative
Preference Ratio
Neutral Equal Importance, equivalent to 1 in the AHP importance scale.
50 / 50
Stronger (S) /
Weaker (W)
Moderate importance of one criteria / option over the other, equivalent to 1.5 in the AHP importance scale.
60 / 40
Much Stronger (MS) /
Much Weaker (MW)
Essential / strong importance of one criteria / option over the other equivalent to 5 or 6 in the AHP importance scale.
75 / 25
Very Much Stronger (VMS) /
Very Much Weaker (VMW)
Extreme importance of one criteria / option over the other equivalent to 8 or 9 in the AHP importance scale.
90 / 10
Table 6.2: Explanation of Phrasing Adopted for Pairwise Comparison
Using this transposed scoring system made it simpler and, more importantly, more effective at capturing the mind-set and feeling of the attendees at the workshops. Phrases such as ‘what are the relative merits of pipeline removal on a project versus rock dumping from a safety perspective? Are these Neutral to each other? Are they stronger? If so, how much stronger? If you had to prioritise one over the other, which would it be?’ This promoted a collaborative dynamic in the workshop and enabled the collective mind-set of the attendees to be captured. Where there was quantitative data to provide back-up and evidence to support the collective assertions, so much the better.
A summary example of the completed pair-wise comparisons for differentiating criteria versus options are shown in Figure 6.2.
Figure 6.2: Example Option Pair-Wise Comparison
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Appendix A.6 Visual Output and Sensitivities
The decision-making tool used the above pairwise comparisons to automatically generate a visual output indicating the highest scoring option i.e. the option which represents the most ‘successful’ solution in terms of its overall contribution to the set of differentiating criteria. At this stage, opportunity was provided to fine tune the judgements provided, to ensure that all attendees were happy to endorse the outcome. The visual outputs from each decision point are included in Appendix C and Appendix D. An example of the visual output obtained is shown in Figure 6.3.
Figure 6.3: CA Visual Output Example
The CA output can then easily be stress tested by the workshop attendees by undertaking a sensitivity analysis:
By applying a modification to the weighting of the criteria – bearing in mind that the base case for this assessment is to have all criteria equally weighted, and / or
Modifying the pair-wise comparison of the options against each other within the criteria where appropriate.
These sensitivities will help inform workshop attendees as to whether a particular aspect is driving a preferred option, or indeed if the preferred option remains the same when the sensitivities are applied.
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APPENDIX B STAKEHOLDER CA WORKSHOP MINUTES
Minutes of Meeting
Subject: Huntington, Caledonia, Hunter, Rita and Johnston Comparative Assessment Stakeholder Review
Location: Premier Oil, Prime Four Business Park, Aberdeen
Date: 8th October 2019
Issued on: 11th November 2019
Attending:
Name Company
Robert Willison
BEIS OPRED ODU Drew Bond
Debbie Taylor
Nicola Abrams BEIS OPRED EMT
Doug Stewart JNCC
Thomas Fey
Ian Rowe NFFO
Steven Alexander SFF
Andrew Third
Hywel Williams HSE
Pieter voor de Poorte
Premier Oil
Paul Newby
Lilla Onodi
Margaret Christie
Martyn Akers
Kate Arman
Phil McIntyre
David Hunt Neptune Energy
Nic Duncan
Xodus John Foreman
Jenny Smith
Distribution: Attendees
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Item Issue Action
1.0 Introduction and Background
1.1 The workshop was introduced by Premier Oil followed by a brief overview of the fields and relevant infrastructure under consideration.
Huntington, cessation of production (CoP) scheduled for 2020.
Caledonia, last production 2010, seabed facilities are currently disconnected at the wellhead and at the Britannia riser.
Hunter and Rita, CoP reached 2018.
Johnston, CoP scheduled for 2022.
Info
2.0 Environmental Baseline
2.1 The environmental baseline and relevant impacts for each field were described by Xodus Group.
Info
2.2 It was noted that the Hornsea Windfarm is in the early planning stages. Should it go ahead, construction would commence in 2025 at the earliest. The wind farm would be located across the Johnston Field and may affect decommissioning of the field.
Info
3.0 Comparative Assessment Review
3.1 The background to the comparative assessment (CA) process conducted to date was provided by Xodus Group, as well as details of the evaluation methodology that would be re-visited during this review workshop.
Info
3.2 Handouts provided for the workshop included:
A set of presentation slides (appended to these minutes)
A set of the criteria and sub-criteria definitions used
A set of the attributes developed for each option used for the evaluation and to be re-appraised for this review workshop.
Info
3.3 Note that the sequence of review was defined to accommodate the availability of specific workshop attendees, focusing on the Southern North Sea (SNS) fields first and the Central North Sea (CNS) fields second.
Info
3.4 Group 4 – Trenched and Buried Flexibles/Umbilical – SNS
3.4.1 An introduction and summary of the infrastructure included within this group was provided.
Rita - 14.33km Static Umbilical - No Exposures (PLU2529)
Johnston - 9.52km Static Umbilical - No Exposure (PLU991) | 6.88km Static Umbilical - No Exposure (PLU2106)
Johnston - 6.89km 8” Production Flexible - No Exposure (PL2105)
3.4.2 Clarification was requested (OPRED) regarding the depth of burial (DoB) for the lines. This was provided by Premier Oil. All of these lines are buried deeper than the recommended 0.6m with no areas of exposure or shallow burial outside of the trench transitions.
3.4.3 Two options were evaluated for this group:
Option 2b – full removal using reverse reel without de-burial.
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Item Issue Action
Option 5 – leave in situ, minimal intervention, remove ends and remediate snag risk.
3.4.4 1.0 Safety
3.4.4.1 1.1 Operational Personnel – no change to evaluated scores.
3.4.4.2 1.2 Other Users – no change to evaluated scores. SIMOPS relating to the windfarm installation and operation was noted as having the same impact on both options.
3.4.4.3 1.3 High Consequence Events – no change to evaluated scores. Clarification was requested (HSE) whether this referred to a specific Reel Vessel or whether this referred to temporary deck mounted reels. Deck mounted reels have been assumed.
3.4.4.4 1.4 Legacy Risk – no change to evaluated scores. A stronger preference for full removal was suggested (JNCC). It was decided to treat this as a sensitivity.
3.4.5 2.0 Environmental
3.4.5.1 2.1 Operational Marine Impacts – no change to evaluated scores. Options scored as neutral, however, some discussion was held regarding the differences in figures but it was agreed that this was not sufficient to drive a difference. It was requested to note that this includes for accidental discharges.
3.4.5.2 2.2 Atmospheric Emissions & Fuel Consumption – no change to evaluated scores.
3.4.5.3 2.3 Other Consumptions – evaluated score favouring Option 2b full removal as Stronger (S) changed to Neutral (N) as although there is a relatively large difference the overall quantities are small and not significant enough to drive a difference.
3.4.5.4 2.4 Seabed Disturbance – evaluated score showing Much Weaker (MW) for the larger area of disturbance changed to Weaker (W) as the actual area is limited.
3.4.5.5 2.5 Legacy Marine Impacts – no change to evaluated scores. A note is to be added to the report that the potential for line exposure over time is not considered a risk.
3.4.6 3.0 Technical
3.4.6.1 3.1 Technical Risk – no change to evaluated scores.
3.4.7 4.0 Societal
3.4.7.1 4.1 Fishing – evaluated score changed from Weaker (W) for full removal to Stronger (S) for full removal. It was noted (NFFO) that significant change is being experienced within the fishing industry due to the implementation of Marine Conservation Zones (MCZ) and the expansion of the renewables sector. As such it is difficult to forecast what type of fishing (static or mobile gear) will predominate in the SNS. It was also highlighted that future disruption from monitoring of infrastructure left in situ is not preferred.
3.4.7.2 4.2 Other Users – evaluated score was changed to Neutral (N) from a Strong (S) preference for full removal as it was considered that the differences were not sufficient to express a preference.
3.4.8 5.0 Economic
3.4.8.1 5.1 Short-Term Costs – no change to evaluated scores.
3.4.8.1 5.2 Long-Term Costs – no change to evaluated scores.
3.4.9 Results
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Item Issue Action
3.4.9.1 Slight preference for full removal. The result is strengthened by economics.
3.5 Group 5 – Trenched and Buried Flexible (failed) /Umbilical – SNS
3.5.1 An introduction and summary of the infrastructure included within this group was provided.
Hunter 8.14km Static Umbilical (PLU2138)
Hunter 8.2km 8” Production Flexible (PL2137) – 18 off exposures
3.5.2 DoB for the lines was provided by Premier Oil. The trenched and buried flexible PL2137 suffered from upheaval buckling (UHB) becoming exposed at 18 locations. During testing it failed and was replaced by a rigid flowline, PL3005. The exposed sections were protected by concrete structures which shall be fully removed. PL2137 shares a trench with an umbilical, PLU2138 with which it is partially entangled.
3.5.3 Four options were evaluated for this group.
Option 2c – Full removal with de-burial (advised by supply chain that prior de-burial is required due to partial entanglement)
Option 4a – Leave in situ, minor, rock placement over exposures
Option 4b – Leave in situ, minor, trench and bury exposures
Option 4c – Leave in situ, minor, remove exposures
3.5.4 1.0 Safety
1.1 Operational Personnel – no change to evaluated scores.
1.2 Other Users – no change to evaluated scores.
1.3 High Consequence Events – no change to evaluated scores.
1.4 Legacy Risk – no change to evaluated scores.
3.5.5 2.0 Environmental
2.1 Operation Marine Impacts – no change to evaluated scores. It was agreed that the contents of the failed flexible flowline was likely already fully released.
2.2 Atmospheric Emissions & Fuel Consumption – no change to evaluated scores. A sensitivity is to be run on a potential preference for Option 2c over all other options. Some discussion was held regards comparison of these options and wider North Sea activities, which concluded that none of these options are significant. Some text should be added to the report to put these figures in context of the wider North Sea emissions.
2.3 Other Consumptions – no change to evaluated scores.
2.4 Seabed Disturbance – no change to evaluated scores. A sensitivity is to be run to change Option 2c from MW against all other options to W.
2.5 Legacy Marine Impacts – evaluated scores changed to reflect the sensitivity of placing any rock at this location. Option 2c against 4a from S to MS, option 2c against 4c from S to MS and Option 4b against 4c from N to S.
3.5.6 3.0 Technical
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Item Issue Action
3.1 Technical Risk – evaluated scores changed for Option 2c against 4a from N to W, Option 2c against 4c from N to MW and Option 4b against 4c from W to MW.
Changes based on experience provided by Neptune Energy on difficulties of reverse reeling, cut and remove exposed sections was considered to be far preferable. It was also agreed that re-trenching would be very challenging.
3.5.7 4.0 Societal
4.1 Fishing – no change to evaluated scores. Whilst full removal is the preferred base case, the type of fishing in the area is changing considerably. A sensitivity is to be run to reflect predominantly static gear fishing in the area in the future which would favour rock dump over full removal.
4.2 Other Users – evaluated scores for Option 2c against all other options changed from S to N.
3.5.8 5.0 Economic
5.1 Short-Term Costs – evaluated scores for Option 2c against Option 4a changed from MW to W for consistency.
5.2 Long-Term Costs – no change to evaluated scores.
3.5.9 Results
Preference for Option 4c, leave in situ, remove exposures.
3.6 Group 2 – Trenched and Buried Rigid Flowlines – SNS
3.6.1 An introduction and summary of the infrastructure included within this group was provided.
Rita 14.07km 8” Production Pipeline – No exposures (PL2528)
Hunter 8.03km 8” Production Pipeline – No exposures (PL3005)
Johnston 9.28km 12” Production Pipeline – No exposures (PL989) | 9.28km 2” Methanol Pipeline (piggybacked onPL989) – No exposures (PL990)
3.6.2 DoB for the lines was provided by Premier Oil.
3.6.3 Two options were evaluated for this group:
Option 2a – full removal using cut and lift with de-burial.
Option 5 – leave in situ, minimal intervention, remove ends and remediate snag risk.
3.6.4 1.0 Safety
1.1 Operational Personnel – no change to evaluated scores.
1.2 Other Users – no change to evaluated scores.
1.3 High Consequence Events – no change to evaluated scores. Clarification was requested on details of the operation. A potential sensitivity was identified whereby Option 2a was scored as MW to Option 5 may be VMW.
1.4 Legacy Risk – no change to evaluated scores.
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Item Issue Action
3.6.5 2.0 Environmental
2.1 Operation Marine Impacts – no change to evaluated scores. A note is to be added to the report to highlight the high level of seabirds in the area and the associated increased level of consequence in the event of a marine diesel release coupled with the longer duration operation.
2.2 Atmospheric Emissions & Fuel Consumption – no change to evaluated scores.
2.3 Other Consumptions – evaluated score for Option 2a against Option 5 changed from S to N for consistency.
2.4 Seabed Disturbance – evaluated score for option 2a against Option 5 changed from VMW to MW, with VMW as a sensitivity. Some discussion held regarding the recovery period for Dogger Bank. The extended recovery period may justify the 90:10 preference associated with the VMW score.
2.5 Legacy Marine Impacts – evaluated score for Option 2a against Option 5 changed from W to S due to rock placement considered worse than short term disturbance.
3.6.6 3.0 Technical
3.1 Technical Risk – no change to evaluated scores.
3.6.7 4.0 Societal
4.1 Fishing- evaluated score for Option 2a against Option 5 changed from W to N due to local disturbance. In this case, as the line is deeply buried, the preference would be to leave in situ (SFF).
4.2 Other Users – no change to evaluated scores.
3.6.8 5.0 Economic
5.1 Short-Term Costs – no change to evaluated scores.
5.2 Long-Term Costs – no change to evaluated scores.
3.6.9 Results
A preference for Option 5, leave in situ, was concluded. A sensitivity was run on 4.1 Fishing to determine the effect of changing N to S in favour of full removal. The result was unchanged.
3.7 Group 1 – Trenched & Buried Rigid Flowlines (CNS)
3.7.1 An introduction and summary of the infrastructure included within this group was provided.
Huntington - 11.8km 8” Gas Export Pipeline - No Exposure (PL2805)
Caledonia - 5.88km 8" / 12" Production Pipe-in-pipe - No Exposure (PL1919)
Caledonia - 5.88km 4" Gas Lift Pipeline (Piggybacked to PL1919) - No Exposure (PL1920)
3.7.2 DoB for the lines was provided by Premier Oil.
3.7.3 Two options were evaluated for this group:
Option 2a – full removal using cut and lift with de-burial.
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Item Issue Action
Option 5 – leave in situ, minimal intervention, remove ends and remediate snag risk.
3.7.4 1.0 Safety
1.1 Operational Personnel – evaluated score for option 2a against Option 5 was changed from MW to W for consistency.
1.2 Other Users – no change to evaluated scores.
1.3 High Consequence Events – no change to evaluated scores.
1.4 Legacy Risk – no change to evaluated scores.
3.7.5 2.0 Environmental
2.1 Operation Marine Impacts – the evaluated score for Option 2a against Option 5 was changed from W to MW for consistency.
2.2 Atmospheric Emissions & Fuel Consumption – no change to evaluated scores.
2.3 Other Consumptions – evaluated score for Option 2a against Option 5 changed from S to N.
2.4 Seabed Disturbance – evaluated score for Option 2a against Option 5 changed from MW to W. Sensitivity to be run with MW due to the recovery duration for the site.
2.5 Legacy Marine Impacts – no change to evaluated scores.
3.7.6 3.0 Technical
3.1 Technical Risk – no change to evaluated scores.
3.7.7 4.0 Societal
4.1 Fishing – no change to evaluated scores.
4.2 Other Users – no change to evaluated scores.
3.7.8 5.0 Economic
5.1 Short-Term Costs – no change to evaluated scores.
5.2 Long-Term Costs – no change to evaluated scores.
3.7.9 Results
A preference for Option 5, leave in situ was concluded.
3.8 Group 3 – Trenched & Buried Flexible Flowlines / Umbilicals (CNS)
3.8.1 An introduction and summary of the infrastructure included within this group was provided.
Huntington - 1.86km 10” Production Flowline - No Exposure (PL2806) | 1.87km 4” Gas Lift Flowline - No Exposure (PL2807)
Huntington - 1.83km 8" Water Injection Flowline - No Exposure (PL2808) | 1.8km Static Umbilical - No Exposure (PLU2809)
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Item Issue Action
Caledonia - 6.05km Static Umbilical - No Exposure (PLU1921)
Note: 10" Production and 4" Gas Lift lines at Huntington are in the same trench. 10" has midline connection (mattressed and buried)
3.8.2 DoB for the lines was provided by Premier Oil.
3.8.3 Two options were evaluated for this group:
Option 2b – full removal using reverse reel without de-burial.
Option 5 – leave in situ, minimal intervention, remove ends and remediate snag risk.
3.8.4 1.0 Safety
1.1 Operational Personnel – evaluated score for Option 2b against Option 5 was changed from MS to S for consistency.
1.2 Other Users – no change to evaluated scores.
1.3 High Consequence Events – no change to evaluated scores.
1.4 Legacy Risk – no change to evaluated scores. A sensitivity will be run for MS instead of S.
3.8.5 2.0 Environmental
2.1 Operation Marine Impacts – no change to evaluated scores.
2.2 Atmospheric Emissions & Fuel Consumption – no change to evaluated scores.
2.3 Other Consumptions – evaluated score for Option 2b against Option 5 was changed from S to N for consistency.
2.4 Seabed Disturbance – no change to evaluated scores.
2.5 Legacy Marine Impacts – no change to evaluated scores.
3.8.6 3.0 Technical
3.1 Technical Risk – no change to evaluated scores.
3.8.7 4.0 Societal
4.1 Fishing – no change to evaluated scores.
4.2 Other Users – evaluated scores for Option 2b against Option 5 changed from S to N for consistency.
3.8.8 5.0 Economic
5.1 Short-Term Costs – no change to evaluated scores.
5.2 Long-Term Costs – no change to evaluated scores.
3.8.9 Results
A preference for Option 2b, full removal was concluded. The result was driven by the shorter length lines in Group 3 and the differences in fishing type in this area in comparison to the SNS.
4.0 Additional Points
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 45
Item Issue Action
4.1 A query was tabled (JNCC) regards lines left in situ and the potential for future lines crossing over or trenching through lines left in situ, such as inter-connectors. It was agreed in the room that future infrastructure installation was beyond the scope of this workshop and should not be a factor in decision making.
4.2 Where results produced are particularly close Premier Oil should firm up on supporting data and re-appraise as required.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 46
APPENDIX C GROUP 1 – DETAILED EVALUATION RESULTS
Appendix C.1 Group 1 Attributes Table
O2a - Full Removal - Cut & Lift with Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
- Flowlines will be disconnected
- Deburial of flowline using MFE
- Recover by cutting into sections and removal
- Flowlines will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
1.
Safe
ty
1.1
Op
era
tio
ns P
ers
on
nel
Vessel Type: PoB / Days / Hours / PLL
Trawler: 5 / 8.0 / 480 / 3.60E-05
Survey Vessel: 44 / 9.5 / 5,005 / 3.75E-04
CSV: 76 / 232.6 / 212,140 / 1.59E-02
Total offshore hours: 217,626 hrs
Total offshore PLL: 1.63E-02
Resource Type: Days / Hours / PLL
Engineering & Management: 2,767.6 / 22,141 / 8.86E-05
Project Management: 3,695.0 / 29,560 / 1.18E-04
Onshore Operations (includes Cleaning & Disposal): 65.0 / 520 / 6.40E-
05
Total onshore hours: 52,221 hrs
Total onshore PLL: 2.71E-04
Total operational hours: 269,847 hrs
Total operational PLL: 1.66E-02
Vessel Type: PoB / Days / Hours / PLL
DSV: 110 / 13.9 / 18,322 / 1.37E-03
Divers: 18 / 13.9 / 5,996 / 5.82E-03
Trawler: 5 / 8.0 / 480 / 3.60E-05
Survey Vessel: 44 / 9.5 / 5,005 / 3.75E-04
Total offshore hours: 29,803 hrs
Total offshore PLL: 7.60E-03
Resource Type: Days / Hours / PLL
Engineering & Management: 348.5 / 2,788 / 1.12E-05
Project Management: 325.0 / 2,600 / 1.04E-05
Onshore Operations (includes Cleaning & Disposal): 2.0 / 16 / 1.97E-06
Total onshore hours: 5,404 hrs
Total onshore PLL: 2.35E-05
Total operational hours: 35,207 hrs
Total operational PLL: 7.63E-03
W
Summary
1.
Safe
ty
1.2
Oth
er
Users
Vessel Days:
Trawler: 8.0
Survey Vessel: 9.5
CSV: 232.6
Total vessel days: 250.1 days
Transits: 30
Vessel Days:
DSV: 13.9
Divers: 13.9
Trawler: 8.0
Survey Vessel: 9.5
Total vessel days: 31.4 days
Transits: 9
W
Summary
1.
Safe
ty
1.3
Hig
h
Co
nseq
uen
ce E
ven
ts Routine operations however this involves a high volume of lifting
operations (148 lifts).
Routine operations with minimal lifting (3 lifts).
MW
Summary
The assessment of the High Consequence Events sub-criterion is as follows:
Option 2a is assessed as being Much Weaker than Option 5 as there is a higher potential for dropped object from the higher number of lifts
associated with Option 2a.
Overall, Option 5 is the preferred option from a High Consequence Events perspective.
The assessment of the Operations Personnel sub-criterion is as follows:
Option 2a is assessed as being Much Weaker than Option 5 as the risk exposure is around 2 times higher due to the extended durations required
to cut the lines into short sections for recovery versus removing the line ends only.
Overall, Option 5 is the preferred option from a risk to Operations Personnel perspective.
The assessment of the Other Users sub-criterion is as follows:
Option 2a is assessed as being Weaker than Option 5 as there is a much higher number of vessel days, the majority of which will be out with any
existing exclusion zones. In addition, there is a higher number of vessel transits to and from the site. Together, these are likely to present a small
increase in safety impact on other users.
Overall, Option 5 is the preferred option from a risk to Other Users perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 47
O2a - Full Removal - Cut & Lift with Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
- Flowlines will be disconnected
- Deburial of flowline using MFE
- Recover by cutting into sections and removal
- Flowlines will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
1.
Safe
ty
1.4
Leg
acy
Ris
k
No legacy risk from this full removal option. The lines would remain in-situ with this option with their full lengths fully
buried.
The survey & monitoring programme is committed to ensuring that the
potential snag hazard from left in-situ infrastructure continues to be
managed & mitigated as appropriate.
S
Summary
2.
En
vir
on
men
tal
2.1
Op
era
tio
nal
Mari
ne I
mp
act
Vessel Noise (days on-site): Survey Vessel 1.48 days | CSV 224.44 days
| Trawler 5 days
Total: 230.92 days
MFE: 7.37 days
Diamond Wire Cutting: 163.7 days
Operation Discharges:
Line cleaning and flushing operations will use Best Environmental
Practice (BEP) and the Best Available Techniques (BAT) to minimise as
far as possible both residual Oil in Water (OIW) and other chemical levels
in lines post flush and discharges to the marine environment during
flushing activities.
Cutting of line ends and midline cuts would lead to an elevated discharge
of fluids from within the lines. However, given the prior cleaning of the
lines, the concentration and quantity of discharge should still be low
overall. Therefore, the related impact is also anticipated to be low.
Vessel Discharges:
This includes Ballast, Grey and Black Water, this is driven by duration of
vessel operations and therefore at 230 days will be the highest of the
options being evaluated.
Vessel Noise (days on-site): Survey Vessel 1.48 days | DSV 9.37 days |
Trawler 5 days
Total: 15.84 days
Dredger: 1.89 days
Hydraulic Shears: 4.54 days
Operation Discharges:
Line cleaning and flushing operations will use Best Environmental
Practice (BEP) and the Best Available Techniques (BAT) to minimise as
far as possible both residual Oil in Water (OIW) and other chemical levels
in lines post flush and discharges to the marine environment during
flushing activities.
Cutting of line ends would lead to an elevated discharge of fluids from
within the lines. However, given the prior cleaning of the lines, the
concentration and quantity of discharge should still be low overall.
Therefore, the related impact is also anticipated to be low.
Vessel Discharges:
This includes Ballast, Grey and Black Water, this is driven by duration of
vessel operations and therefore at 16 days will be the lowest of the
options being evaluated.
MW
Summary
2.
En
vir
on
men
tal
2.2
Atm
osp
heri
c
Em
issio
ns &
Fu
el
Co
nsu
mp
tio
n
Vessel Emissions (in tonnes):
Fuel: 1,403
CO2: 4,449
NOx: 83.36
SO2: 5.61
Vessel Energy Use: 60,348 GJ
Vessel Emissions (in tonnes):
Fuel: 1,390
CO2: 4,407
NOx: 82.58
SO2: 5.56
Vessel Energy Use: 59,782 GJ
N
Summary
The assessment of the Operational Marine Impact sub-criterion is as follows:
Option 2a is assessed as being Much Weaker than Option 5 as there is more marine noise from the extended vessel operations, diamond wire
cutting and MFE operations. There would also be more discharges associated with the higher number of vessel days and increased operational
discharges from cutting the pipeline into small sections. There is also more potential for accidiental release from having the hydraulic shears in the
water for long durations and for diesel spill from vessels during longer duration of operations in Option 2A. It is noted that all these impacts are
relatively minor with the cumulative impact being sufficient to express a small preference for Option 5.
Overall, Option 5 is the preferred option from an Operational Marine Impact perspective.
The assessment of the Atmospheric Emissions & Consumptions sub-criterion is as follows:
Option 2a is assessed as being Neutral to Option 5 as the fuel use and atmospheric emissions are largely similar with the differences insufficient to
express a preference.
Overall, both options are equally preferred from an Atmospheric Emissions & Consumptions perspective.
The assessment of the Legacy Risk sub-criterion is as follows:
Option 2a is assessed as being Stronger than Option 5 as there is no legacy risk from the full removal option versus a small potential for a snag
hazard from the fully buried lines with rock placement at the cut ends although this risk is mitigated by the survey and monitoring campaign.
Overall, Option 2a is the preferred option from a Legacy Risk perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 48
O2a - Full Removal - Cut & Lift with Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
- Flowlines will be disconnected
- Deburial of flowline using MFE
- Recover by cutting into sections and removal
- Flowlines will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
2.
En
vir
on
men
tal
2.3
Oth
er
Co
nsu
mp
tio
ns Material Emissions (CO2 in tonnes):
Recovered Material: 1,943
Remaining Material:
Total: 1,943
Rock: N/A tonnes
Material Emissions (CO2 in tonnes):
Recovered Material: 60
Remaining Material: 3,533
Total: 3,593
Rock: 100 tonnes
N
Summary
2.
En
vir
on
men
tal
2.4
Seab
ed
Dis
turb
an
ce
Short Term Disturbance (MFE): 88,400 m2 Short Term Disturbance (Dredging): 40 m2
MW
Summary
2.
En
vir
on
men
tal
2.5
Leg
acy M
ari
ne
Imp
acts
No legacy marine impact from this full removal option.
Habitat Loss (Rockdump): N/A
Line cleaning and flushing operations will use Best Environmental
Practice (BEP) and the Best Available Techniques (BAT) to minimise as
far as possible both residual Oil in Water (OIW) and other chemical levels
in lines post flush.
The legacy marine impact from the slow release of these low
concentration / quantity discharges and any line degradation products is
therefore expected to be low overall.
Habitat Loss (Rockdump): 40 m2
S
Summary
3.
Tech
nic
al
3.1
Tech
nic
al
Ris
k Concept Maturity: The concept is well proven. (Score 3) Current tooling
is not proven in use but uses DWC & subsea grabbers which are with the
score of 3 reflecting that confidence is high that concept is ok. Basis of
development of tool will be to have redundancy built in and spare tool
available.
Technical Risks: The length of pipe and depth of burial may present
some technical challenges. (Score 2)
Concept Maturity: Minimal operations, well proven techniques. (Score 3)
Technical Risks: Limited technical risks associated with option (Score
3)
W
Summary
The assessment of the Other Consumptions sub-criterion is as follows:
Option 2a is assessed as being Stronger than Option 5 as the impact from processing all returned material in the full removal option is around half
the impact from producing replacement material for the lines left in-situ.
Overall, both options are equally preferred from an Other Consumptions perspective.
The assessment of the Seabed Disturbance sub-criterion is as follows:
Option 2a is assessed as being Much Weaker than Option 5 due to the much greater area of seabed disturbed during the deburial of the lines by
MFE in Option 2a coupled with the time it would take for the seabed to recover in this geographic location.
Overall, Option 5 is the preferred option from a Seabed Disturbance perspective.
The assessment of the Legacy Marine Impacts sub-criterion is as follows:
Option 2a is assessed as being Stronger than Option 5 as there is no legacy marine impact from Option 2a versus a small legacy impact from the
lines being left in-situ. There is also a small area of permanent habitat change due to the small area of rock cover.
Overall, Option 2a is the preferred option from a Legacy Marine Impacts perspective.
The assessment of the Technical Risk sub-criterion is as follows:
Option 2a is assessed as being Weaker than Option 5 as whilst both options use largely proven technology and routine operations, the extensive
cut and lift and deburial operations in Option 2a carry more risk of technical failure.
Overall, Option 5 is the preferred option from a Technical Risk perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 49
O2a - Full Removal - Cut & Lift with Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
- Flowlines will be disconnected
- Deburial of flowline using MFE
- Recover by cutting into sections and removal
- Flowlines will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
4.
So
cie
tal
4.1
Fis
hin
g
Vessels will be working in the area for a significant number of days
causing disruption to any local fishing activities, particularly nethrop
fishing. (Score 2)
Minimal disturbance to fishing operations. (Score 3)
N
Summary
4.
So
cie
tal
4.2
Oth
er
Users
A reasonable amount of steel can be recovered with this option with
minimal material requiring to go to landfill. (Score 3)
Materials Returned:
Steel: 1,930 tonnes (recyclable)
Minimal societal benefits / impacts with this option. (Score 3)
Materials Returned:
Steel: 60 tonnes (recyclable)
S
Summary
5.
Eco
no
mic
5.1
Sh
ort
-term
Co
sts
£36.221 Million £3.366 Million
VMW
Summary
5.
Eco
no
mic
5.2
Lo
ng
-term
Co
sts
Surveys: N/A
FLTC: N/A
Total Legacy Cost: £0 Million
Surveys: £0.946 Million
FLTC: N/A
Total Legacy Cost: £0.946 Million
S
Summary
The assessment of the Long-term Costs sub-criterion is as follows:
Option 2a is assessed as being Stronger than Option 5 as there are no long-term costs associated with the full removal option.
Overall, Option 2a is the preferred option from a Long-term Cost perspective.
The assessment of the Societal impact on Other Users sub-criterion is as follows:
Option 2a is assessed as being Stronger than Option 5 as there is a significantly higher quantity of useful material being returned in Option 2a.
Overall, Option 2a is the preferred option from a Societal impact on Other Users perspective.
The assessment of the Societal impact on Fishing sub-criterion is as follows:
Option 2a is assessed as being Neutral to Option 5 as whilst it is preferred that lines be fully removed, the disruption caused by the deburial and
removal of the lines in Option 2a may have impact on nethrops fishing activities which are prevalent in this area.
Overall, both options are equally preferred from a Societal impact on Fishing perspective.
The assessment of the Short-term Costs sub-criterion is as follows:
Option 2a is assessed as being Very Much Weaker than Option 5 as the costs are around 12 times higher.
Overall, Option 5 is the preferred option from a Short-term Cost perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 50
Appendix C.2 Group 1 Pairwise Comparison Matrices - Safety
1.1 Operations
Personnel
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN W 40.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
S N 60.0%
1.2 Other Users
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN W 40.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
S N 60.0%
1.3 High
Consequence
Events
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN MW 25.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
MS N 75.0%
1.4 Legacy Risk
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 51
Appendix C.3 Group 1 Pairwise Comparison Matrices - Environment
2.1 Operational
Marine Impact
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN MW 25.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
MS N 75.0%
2.2 Atmospheric
Emissions & Fuel
Consumption
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
2.3 Other
Consumptions
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
2.4 Seabed
Disturbance
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN MW 25.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
MS N 75.0%
2.5 Legacy Marine
Impacts
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 52
Appendix C.4 Group 1 Pairwise Comparison Matrices – Technical
Appendix C.5 Group 1 Pairwise Comparison Matrices – Societal
Appendix C.6 Group 1 Pairwise Comparison Matrices - Economic
3.1 Technical Risk
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN W 40.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
S N 60.0%
4.1 Fishing
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
4.2 Other UsersO
2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
5.1 Short-term
Costs
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN VMW 10.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
VMS N 90.0%
5.2 Long-term
Costs
O2a -
Fu
ll R
em
oval
- C
ut
&
Lif
t w
ith
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2a - Full Removal - Cut &
Lift with DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 53
Appendix C.7 Group 1 Results Charts
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 54
APPENDIX D GROUP 3 – DETAILED EVALUATION RESULTS
Appendix D.1 Group 3 Attributes Table
O2b - Full Removal - Reverse Reel w/o Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
- Flowlines / umbilicals will be disconnected
- No Deburial
- Recover by cutting into sections and removal
- Flowlines / umbilicals will be disconnected
- Removal and recovery of surface laid sections out with existing trench
- Rock placement to remediate snag risk from cut ends
1.
Safe
ty
1.1
Op
era
tio
ns P
ers
on
nel
Vessel Type: PoB / Days / Hours / PLL
DSV: 110 / 6.5 / 8,580 / 6.44E-04
Divers: 18 / 6.5 / 2,808 / 2.72E-03
Trawler: 5 / 8.0 / 480 / 3.60E-05
Survey Vessel: 44 / 9.1 / 4,815 / 3.61E-04
CSV: 76 / 8.1 / 7,405 / 5.55E-04
Total offshore hours: 24,089 hrs
Total offshore PLL: 4.32E-03
Resource Type: Days / Hours / PLL
Engineering & Management: 275.0 / 2,200 / 8.80E-06
Project Management: 250.0 / 2,000 / 8.00E-06
Onshore Operations (includes Cleaning & Disposal): 34.0 / 272 / 3.35E-
05
Total onshore hours: 4,472 hrs
Total onshore PLL: 5.03E-05
Total operational hours: 28,561 hrs
Total operational PLL: 4.37E-03
Vessel Type: PoB / Days / Hours / PLL
DSV: 110 / 26.2 / 34,518 / 2.59E-03
Divers: 18 / 26.2 / 11,297 / 1.10E-02
Trawler: 5 / 8.0 / 480 / 3.60E-05
Survey Vessel: 44 / 9.1 / 4,815 / 3.61E-04
Total offshore hours: 51,110 hrs
Total offshore PLL: 1.39E-02
Resource Type: Days / Hours / PLL
Engineering & Management: 617.6 / 4,941 / 1.98E-05
Project Management: 577.0 / 4,616 / 1.85E-05
Onshore Operations (includes Cleaning & Disposal): 4.0 / 32 / 3.94E-06
Total onshore hours: 9,589 hrs
Total onshore PLL: 4.22E-05
Total operational hours: 60,699 hrs
Total operational PLL: 1.40E-02
S
Summary
1.
Safe
ty
1.2
Oth
er
Users
Vessel Days:
DSV: 6.5
Divers: 6.5
Trawler: 8.0
Survey Vessel: 9.1
CSV: 8.1
Total vessel days: 31.7 days
Transits: 12
Vessel Days:
DSV: 26.2
Divers: 26.2
Trawler: 8.0
Survey Vessel: 9.1
Total vessel days: 43.3 days
Transits: 9
N
Summary
1.
Safe
ty
1.3
Hig
h
Co
nseq
uen
ce E
ven
ts Integrity assumed by engineering only and as such reverse reeling has
the potential for integrity failure.
There are 5 lines and therefore there will be a minimum of 5 lifts from
vessel to shore.
Routine operations - Minimal lifting (c. 10 lifts offshore and onshore).
N
Summary
The assessment of the High Consequence Events sub-criterion is as follows:
Option 2b is assessed as being Neutral to Option 5 as the potential for dropped object is similar as the number of lifts are similar. The HAZID
indicated that the potential for High Consequence Events from an integrity failure of the line during reverse reeling would be negligible due to no
personnel being exposed on high tension side of the tensioner.
Overall, both options are equally preferred from a High Consequence Events perspective.
The assessment of the Other Users sub-criterion is as follows:
Option 2b is assessed as being Neutral to Option 5 as the number of vessel days and transits are largely similar and as such, the safety impact on
other users is likely to be similar.
Overall, both options are equally preferred from a risk to Other Users perspective.
The assessment of the Operations Personnel sub-criterion is as follows:
Option 2b is assessed as being Stronger than Option 5 as the risk exposure is around a third due to the extended durations required to cut the line
ends into short sections for recovery versus the efficient reverse reeling operations.
Overall, Option 2b is the preferred option from a risk to Operations Personnel perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 55
O2b - Full Removal - Reverse Reel w/o Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
1.
Safe
ty
1.4
Leg
acy R
isk
No legacy risk from this full removal option. The lines would remain in-situ with this option with their full lengths fully
buried.
The survey & monitoring programme is committed to ensuring that the
potential snag hazard from left in-situ infrastructure continues to be
managed & mitigated as appropriate.
S
Summary
2.
En
vir
on
men
tal
2.1
Op
era
tio
nal
Mari
ne I
mp
act
Vessel Noise (days on-site): Survey Vessel 1.12 days | DSV 2.5 | CSV
3.11 days | Trawler 5 days
Total: = 11.73 days
No cutting
Operation Discharges:
Line cleaning and flushing operations will use Best Environmental
Practice (BEP) and the Best Available Techniques (BAT) to minimise as
far as possible both residual Oil in Water (OIW) and other chemical levels
in lines post flush and discharges to the marine environment during
flushing activities.
Cutting of line ends and reverse reeling would lead to an elevated
discharge of fluids from within the lines. However, given the prior cleaning
of the lines, the concentration and quantity of discharge should still be
low overall. Therefore, the related impact is also anticipated to be low.
Vessel Discharges:
This includes Ballast, Grey and Black Water, this is driven by duration of
vessel operations and therefore at 12 days is similar to the other option
being evaluated.
Vessel Noise (days on-site): Survey Vessel 1.12 days | DSV 24.08 days |
Trawler 5 days
Total: 30.15 days
Dredger: 5.34 days
Hydraulic Shears: 10.68 days
Operation Discharges:
Line cleaning and flushing operations will use Best Environmental
Practice (BEP) and the Best Available Techniques (BAT) to minimise as
far as possible both residual Oil in Water (OIW) and other chemical levels
in lines post flush and discharges to the marine environment during
flushing activities.
Cutting of line ends would lead to an elevated discharge of fluids from
within the lines. However, given the prior cleaning of the lines, the
concentration and quantity of discharge should still be low overall.
Therefore, the related impact is also anticipated to be low.
Vessel Discharges:
This includes Ballast, Grey and Black Water, this is driven by duration of
vessel operations and therefore at 30 days is similar to the other option
being evaluated.
N
Summary
2.
En
vir
on
men
tal
2.2
Atm
osp
heri
c E
mis
sio
ns
& F
uel
Co
nsu
mp
tio
n
Vessel Emissions (in tonnes):
Fuel: 362
CO2: 1,147
NOx: 21.50
SO2: 1.45
Vessel Energy Use: 15,565 GJ
Vessel Emissions (in tonnes):
Fuel: 1,585
CO2: 5,024
NOx: 94.15
SO2: 6.34
Vessel Energy Use: 68,154 GJ
N
Summary
The assessment of the Operational Marine Impact sub-criterion is as follows:
Option 2b is assessed as being Neutral to Option 5 as the marine noise impact and discharges from vessels is largely similar for both options.
There would be higher operational discharges from reverse reeling the lines as all contents would be released in a single discharge, however the
impact of this is expected to be low and insufficient to express a preference as the inventory would be very small as these short lines will already
have been cleaned and flushed.
Overall, both options are equally preferred from an Operational Marine Impact perspective.
The assessment of the Atmospheric Emissions & Consumptions sub-criterion is as follows:
Option 2b is assessed as being Neutral to Option 5 as, whilst there 4 times the fuel use and emissions for Option 5, this difference is insufficient to
express a preference from an environmental impact perspective.
Overall, both options are equally preferred from an Atmospheric Emissions & Consumptions perspective.
The assessment of the Legacy Risk sub-criterion is as follows:
Option 2b is assessed as being Stronger than Option 5 as there is no legacy risk from the full removal option versus a small potential for a snag
hazard from the fully buried lines with rock placement at the cut ends although this risk is mitigated by the survey and monitoring campaign.
Overall, Option 2b is the preferred option from a Legacy Risk perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 56
O2b - Full Removal - Reverse Reel w/o Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
2.
En
vir
on
men
tal
2.3
Oth
er
Co
nsu
mp
tio
ns
Material Emissions (CO2 in tonnes):
Recovered Material: 579
Remaining Material:
Total: 579
Rock: N/A tonnes
Material Emissions (CO2 in tonnes):
Recovered Material: 56
Remaining Material: 1,057
Total: 1,113
Rock: 400 tonnes
N
Summary
2.
En
vir
on
men
tal
2.4
Seab
ed
Dis
turb
an
ce
Short Term Disturbance (Reverse Reeling): 24,256 m2 Short Term Disturbance (Rock Cover): 100 m2
W
Summary
2.
En
vir
on
men
tal
2.5
Leg
acy M
ari
ne
Imp
acts
No legacy marine impact from this full removal option.
Habitat Loss (Rockdump): N/A
Line cleaning and flushing operations will use Best Environmental
Practice (BEP) and the Best Available Techniques (BAT) to minimise as
far as possible both residual Oil in Water (OIW) and other chemical levels
in lines post flush.
The legacy marine impact from the slow release of these low
concentration / quantity discharges is therefore expected to be low
overall.
Habitat Loss (Rockdump): 100 m2
S
Summary
3.
Tech
nic
al
3.1
Tech
nic
al
Ris
k Concept Maturity: Proven technique, however integrity of line to be
pulled through soils needs to be confirmed. (Score 2)
Technical Risks: The potential for technical failure and the requirement
to re-assess option remains. (Score 2)
Concept Maturity: Minimal operations, well proven techniques. (Score 3)
Technical Risks: Limited technical risks associated with option (Score
3)
W
Summary
The assessment of the Seabed Disturbance sub-criterion is as follows:
Option 2b is assessed as being Weaker than Option 5 due to the greater area of seabed disturbed by reverse reeling the lines through cover in
Option 2b.
Overall, Option 5 is the preferred option from a Seabed Disturbance perspective.
The assessment of the Legacy Marine Impacts sub-criterion is as follows:
Option 2b is assessed as being Stronger than Option 5 as there is no legacy marine impact from Option 2b versus a small legacy impact from the
lines being left in-situ. There is also a small area of permanent habitat change due to the small area of rock cover.
Overall, Option 2b is the preferred option from a Legacy Marine Impacts perspective.
The assessment of the Other Consumptions sub-criterion is as follows:
Option 2b is assessed as being Stronger than Option 5 as the impact from processing all returned material in the full removal option is around half
the impact from producing replacement material for the lines left in-situ.
Overall, Option 2b is the preferred option from an Other Consumptions perspective.
The assessment of the Technical Risk sub-criterion is as follows:
Option 2b is assessed as being Weaker than Option 5 as whilst both options use proven technology and routine operations, there is potential for the
reverse reeling option to fail, requiring the decommissioning solution to be revisited. This was sufficient to express a small preference for Option 5.
Overall, Option 5 is the preferred option from a Technical Risk perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 57
O2b - Full Removal - Reverse Reel w/o Deburial O5 - Leave - Minimal - Remove Ends & Remediate Snag Risk
4.
So
cie
tal
4.1
Fis
hin
g
Short duration operation, small short-term area of disturbance, Fishing
operations are conducted in vicinity of the pipeline and back-filling to
remove berms may be required. (Score 2)
Minimal disturbance to fishing operations. (Score 3)
N
Summary
4.
So
cie
tal
4.2
Oth
er
Users
A significant amount of material will require to go to land-fill. (Score 2)
Materials Returned:
Steel: 548 tonnes (recyclable)
Copper: 19 tonnes (recyclable)
Polymer: 428 tonnes (landfill)
Minimal societal benefits / impacts with this option. (Score 3)
Materials Returned:
Steel: 53 tonnes (recyclable)
Copper: 2 tonnes (recyclable)
Polymer: 41 tonnes (landfill)
N
Summary
5.
Eco
no
mic
5.1
Sh
ort
-term
Co
sts
£2.629 Million £5.821 Million
S
Summary
5.
Eco
no
mic
5.2
Lo
ng
-term
Co
sts
Surveys: N/A
FLTC: N/A
Total Legacy Cost: £0 Million
Surveys: £0.908 Million
FLTC: N/A
Total Legacy Cost: £0.908 Million
S
Summary
The assessment of the Societal impact on Fishing sub-criterion is as follows:
Option 2b is assessed as being Neutral to Option 5 as whilst it is preferred that lines be fully removed, the disruption caused by reverse reeling the
lines in Option 2b may have impact on nethrops fishing activities which are prevalent in this area.
Overall, both options are equally preferred from a Societal impact on Fishing perspective.
The assessment of the Societal impact on Other Users sub-criterion is as follows:
Option 2b is assessed as being Neutral to Option 5 as, whilst there is more useful material returned in Option 2b, there is also more material
destined for landfill which cancels this out.
Overall, both options are equally preferred from a Societal impact on Other Users perspective.
The assessment of the Short-term Costs sub-criterion is as follows:
Option 2b is assessed as being Stronger than Option 5 as the costs are around half that of Option 5.
Overall, Option 2b is the preferred option from a Short-term Cost perspective.
The assessment of the Long-term Costs sub-criterion is as follows:
Option 2b is assessed as being Stronger than Option 5 as there are no long-term costs associated with the full removal option.
Overall, Option 2b is the preferred option from a Long-term Cost perspective.
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 58
Appendix D.2 Group 3 Pairwise Comparison Matrices - Safety
1.1 Operations
Personnel
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
1.2 Other Users
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
1.3 High
Consequence
Events
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
1.4 Legacy Risk
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 59
Appendix D.3 Group 3 Pairwise Comparison Matrices - Environment
2.1 Operational
Marine Impact
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
2.2 Atmospheric
Emissions & Fuel
Consumption
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
2.3 Other
Consumptions
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
2.4 Seabed
DisturbanceO
2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN W 40.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
S N 60.0%
2.5 Legacy Marine
Impacts
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 60
Appendix D.4 Group 3 Pairwise Comparison Matrices – Technical
Appendix D.5 Group 3 Pairwise Comparison Matrices - Societal
Appendix D.6 Group 3 Pairwise Comparison Matrices - Economic
3.1 Technical Risk
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN W 40.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
S N 60.0%
4.1 Fishing
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
4.2 Other Users
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN N 50.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
N N 50.0%
5.1 Short-term
Costs
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
5.2 Long-term
Costs
O2b
- F
ull
Rem
oval
-
Revers
e R
eel
w/o
Deb
uri
al
O5 -
Leave -
Min
imal
-
Rem
ove E
nd
s &
Rem
ed
iate
Sn
ag
Ris
k
Weig
hti
ng
O2b - Full Removal -
Reverse Reel w/o DeburialN S 60.0%
O5 - Leave - Minimal -
Remove Ends & Remediate
Snag Risk
W N 40.0%
CA and EA Services – Huntington Field Comparative Assessment Report
Assignment Number: A302470-S00
Document Number: A-302470-S00-REPT-005 61
Appendix D.7 Group 3 Results Charts